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As confidentially submitted to the Securities and Exchange Commission on November 6, 2014
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Confidential Draft Submission No. 1
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Centennial Resource Development, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 1311 | 47-2040396 | ||
(State or other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (IRS Employer Identification Number) |
1401 17th Street, Suite 1000
Denver, CO 80202
(720) 441-5515
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
George S. Glyphis
Chief Financial Officer
1401 17th Street, Suite 1000
Denver, CO 80202
(720) 441-5515
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
Douglas E. McWilliams Christopher G. Schmitt Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222 | Gerald M. Spedale Andrew J. Ericksen Baker Botts L.L.P. One Shell Plaza 901 Louisiana St. Houston, Texas 77002 (713) 229-1234 |
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, 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 | þ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
CALCULATION OF REGISTRATION FEE
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Title of Each Class of Securities to be Registered | Proposed Maximum Aggregate Offering Price (1)(2) | Amount of Registration Fee(3) | ||
Common Stock, par value $0.01 per share | $ | $ | ||
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(1) | Includes shares issuable upon exercise of the underwriters’ option to purchase additional shares of 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. |
(3) | To be paid in connection with the initial filing of the registration statement. |
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. The securities described herein may not be sold 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 or jurisdiction where the offer or sale is not permitted.
Subject to Completion, dated , 2014
PROSPECTUS
Shares
Centennial Resource Development, Inc.
Common Stock
This is the initial public offering of the common stock of Centennial Resource Development, Inc., a Delaware corporation. We are offering shares of our common stock, and the selling stockholders identified in this prospectus are offering shares. We will not receive any proceeds from the sale of shares by the selling stockholders. No public market currently exists for our common stock. We are an “emerging growth company” and are eligible for reduced reporting requirements. Please see “Prospectus Summary—Emerging Growth Company.”
We intend to apply to list our common stock on the New York Stock Exchange under the symbol “CDEV.”
We anticipate that the initial public offering price will be between $ and $ per share.
Investing in our common stock involves risks. See “Risk Factors” beginning on page 21 of this prospectus.
Per share | Total | |||||||
Price to the public | $ | $ | ||||||
Underwriting discounts and commissions | $ | $ | ||||||
Proceeds to us (before expenses) | $ | $ | ||||||
Proceeds to the selling stockholders (before expenses) | $ | $ |
The selling stockholders have granted the underwriters the option to purchase up to additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than shares of common stock in this offering.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the shares on or about , 2015 through the book-entry facilities of The Depository Trust Company.
Barclays
Prospectus dated , 2015
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SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL DATA | 54 | |||
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 57 | |||
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You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. Neither we, the selling stockholders 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 stockholders and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of 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 delivery of this prospectus or any sale of the 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 Statement Regarding Forward-Looking Statements.”
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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. Although we believe these third-party sources are reliable as of their respective dates, neither we, the selling stockholders nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. 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.
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 us or an 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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This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and pro forma financial statements and the notes to those financial statements appearing elsewhere in this prospectus. The information presented in this prospectus assumes (i) an initial public offering price of $ per common share (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 common stock.
On October 15, 2014, Centennial Resource Production, LLC (“Centennial OpCo”), an independent oil and natural gas company formed on August 30, 2012, acquired all of the oil and natural gas properties and certain other assets of Celero Energy Company, LP (“Celero”) in exchange for interests in Centennial OpCo, which is referred to in this prospectus as the Combination. Prior to the effectiveness of the registration statement of which this prospectus forms a part, we will complete a corporate reorganization pursuant to which all of the interests in Centennial OpCo, including Celero’s interests, will be contributed to Centennial Resource Development, Inc., a recently formed Delaware corporation and the issuer of common stock in this offering, in exchange for shares of common stock in Centennial Resource Development, Inc. Except as expressly stated or the context otherwise requires, our financial, reserve and operating information in this prospectus gives effect to the Combination, and the terms “we,” “us” and “our” refer, prior to the corporate reorganization, to the consolidated and combined financial, reserve and operating information of Centennial OpCo and Celero, and, after the corporate reorganization, to Centennial Resource Development, Inc. and its subsidiaries. Please read “Recent and Formation Transactions.”
This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in the “Glossary of Oil and Natural Gas Terms.”
Our Company
Business Overview
We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our properties consist of large, contiguous acreage blocks primarily in Reeves, Ward and Pecos counties in West Texas.
As of September 30, 2014, our portfolio included 35 producing horizontal wells, which represented approximately % of our production. Our horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe our acreage is prospective for the 2nd Bone Spring and Avalon Shale zones, where other operators have experienced drilling success near our acreage.
We have leased or acquired approximately 40,500 net acres as of September 30, 2014, approximately 81% of which we operate. We currently operate four horizontal rigs, and we expect to add a fifth horizontal rig in the second quarter of 2015 and a sixth horizontal rig in the second half of 2015. Since January 2013, all of our wells drilled in the Delaware Basin have been horizontal wells. We plan to continue this horizontal drilling program with an ongoing focus on optimizing completions and reducing costs.
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The Permian Basin is an attractive operating area due to its extensive original oil-in-place, favorable operating environment, multiple horizontal zones, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. According to the Energy Information Administration of the U.S. Department of Energy (the “EIA”), the Permian Basin is the most prolific oil producing area in the United States, accounting for 18% of total U.S. crude oil production in 2013. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin.
Horizontal drilling activity has historically been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. According to Baker Hughes, four of the top six Permian Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county with 50 rigs as of September 30, 2014. The number of horizontal rigs within the Permian Basin, and specifically Reeves County, has been subject to a significant upward trend over the past year. As shown in the chart below, Reeves County currently has the most horizontal rigs in the Permian Basin, and the rig count has grown approximately 213% in the last twelve months.
We were formed by an affiliate of Natural Gas Partners (“NGP”), a family of energy-focused private equity investments funds. Our goal is to build the premier development and acquisition company focused on horizontal drilling in the Delaware Basin. Our key management and technical team members average approximately 26 years of experience and have successfully led development operations in prolific oil basins in the Continental United States, including horizontal development in the Permian, Bakken and Niobrara plays. This expertise and technical acumen have been applied to the horizontal drilling and multi-stage completions on our properties, resulting in drilling success and continuous operating improvements across multiple zones.
We have assembled a multi-year inventory of horizontal drilling projects. As of September 30, 2014, we had identified 1,232 gross horizontal drilling locations in the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C zones across our Delaware Basin acreage based on spacing of five to six wells per zone per 640-acre section. We believe that development drilling of these locations, as well as further downspacing, will allow us to grow our production and reserves. In addition, we believe we will improve well economics via drilling optimization, including reduction of spud-to-rig release days and increased use of pad drilling. Furthermore, we plan to pursue accretive acquisitions that are complementary to our strategic and financial objectives.
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Our near term drilling program is focused on the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C zones. Based upon our and other operators’ well results and our analysis of geologic and engineering data, we believe the 2nd Bone Spring and Avalon Shale formations may also be prospective across our acreage, and we may integrate these zones into our future drilling program as they become further delineated. We believe our large acreage blocks allow us to optimize our horizontal development program to maximize our resource recovery and our returns. The following table provides a summary of our gross horizontal drilling locations by zone as of September 30, 2014.
Gross Identified Horizontal Drilling Locations(1)(2) | ||||
Total | ||||
Zones: | ||||
3rd Bone Spring | 69 | |||
Upper Wolfcamp A | 414 | |||
Lower Wolfcamp A | 353 | |||
Wolfcamp B | 85 | |||
Wolfcamp C | 311 | |||
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Total Horizontal Locations(3)(4) | 1,232 | |||
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(1) | Our total identified horizontal drilling locations include 47 locations associated with proved undeveloped reserves as of September 30, 2014. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our combined horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. See “Business—Our Properties.” The drilling locations that 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 ability to add additional proved reserves to our existing proved reserves. See “Risk Factors—Risks Related to Our Business—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.” Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See “Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled out 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.” |
(2) | Our horizontal drilling location count implies 880 foot spacing with five to six wells per zone per 640 acres consisting primarily of approximately 4,400 foot laterals. |
(3) | 653 of our 1,232 horizontal drilling locations are on acreage that we operate. We have an approximately 88% average working interest in our operated locations and an approximately 16% average working interest in our non-operated locations. |
(4) | We have included undeveloped horizontal locations only on our leasehold in Reeves and Ward counties. In addition to the 1,232 horizontal drilling locations, we have 34 gross identified vertical drilling locations on acreage that we operate in the Central Basin platform in Ward County, Texas. |
Our 2014 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $335 million, excluding leasing and other acquisitions. In the six months ended June 30, 2014, we incurred capital costs of approximately $160 million. We currently estimate that our 2015 capital budget for drilling, completion and recompletion activities and facilities costs will be approximately $ million. We expect that approximately % of our 2015 drilling and completion budget, or $ million, will be devoted to
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the drilling of horizontal wells. In 2015, we expect to allocate approximately $ million of our capital budget for the drilling and completion of operated wells and $ million for our participation in the drilling and completion of non-operated wells.
Because we operate approximately 81% of our net acreage, the amount and timing of these capital expenditures are largely subject to our discretion. We believe our approximately 88% average working interest in our operated locations, as compared to our 16% average working interest in our non-operated locations, provides us with flexibility to manage our drilling program and optimize our returns and profitability. We could choose to defer a portion of our planned 2015 capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, NGLs and natural gas; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.
For the three months ended June 30, 2014, after giving effect to the CO2 Project Disposition (which is discussed under “Recent and Formation Transactions—Recent Acquisitions and Dispositions—CO2 Project Disposition”), our average net daily production was 5,020 Boe/d (approximately 77% oil and 23% liquids-rich natural gas). The following chart provides information regarding our quarterly production growth.
(1) | Net daily production is pro forma for the Dispositions and reflects only properties owned by us as of June 30, 2014. Please see “Recent and Formation Transactions—Recent Acquisitions and Dispositions” for a discussion of the Dispositions. |
The following table provides summary information regarding our proved reserves as of September 30, 2014, based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineer. Of our proved reserves, approximately 38% were classified as proved developed producing (“PDP”) and 2% as proved developed non-producing (“PDNP”). Proved undeveloped reserves (“PUDs”) included in this estimate are from 47 horizontal well locations across five zones and eight vertical well locations.
Estimated Total Proved Reserves | ||||||||||||
Oil | NGLs | Natural Gas | Total | % Oil | % Liquids(2) | % Developed | ||||||
17.0 | 1.3 | 20.7 | 21.8 | 78 | 84 | 40 |
(1) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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) | Includes oil and NGLs. |
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Business Strategies
Our primary business objective is to increase stockholder value through the following strategies:
• | Grow production, cash flow and reserves by developing our extensive Delaware Basin drilling inventory. Our horizontal drilling expertise and technical acumen have enabled us to successfully drill horizontal wells across the areal extent of our acreage while targeting multiple horizontal zones. We have identified a drilling inventory of 1,232 horizontal drilling locations across five zones, which we believe can be expanded via other stacked pay zones accessible on our leasehold. Currently, we operate four horizontal drilling rigs focused on the Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp C zones, and we plan to accelerate our growth by adding a fifth horizontal drilling rig in the second quarter of 2015 and a sixth horizontal drilling rig in the second half of 2015. We plan to also target the 3rd Bone Spring and Wolfcamp B zones in our 2015 drilling program. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe this strategy will allow us to significantly grow our production, cash flow and reserves while efficiently allocating capital to maximize the value of our resource base. |
• | Maximize returns by optimizing drilling and completion techniques and improving operating efficiency.We believe completion design combined with cost reductions are the biggest drivers affecting field-level economics. We seek to optimize our wellbore economics and consequently increase net asset value growth through a methodical and continuous focus on rig efficiency, wellbore accuracy, completion design and execution. We have also improved our completion techniques by reducing perforation spacing and increasing frac stages and the amount of proppant used. We closely monitor offset operators to learn from their operational results and apply best practices to our own drilling plan to enhance returns. |
• | Maintain a high degree of operational control. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies. As the operator of 81% of our net acreage, we are able to manage (i) the timing and level of our capital spending, (ii) our development drilling strategies and (iii) our operating costs. We believe this flexibility to manage our drilling program allows us to optimize our returns and profitability. |
• | Leverage extensive acquisition experience to evaluate and pursue accretive opportunities. Our executive and core technical team has an average of approximately 26 years of industry experience. Our team has significant experience in successfully evaluating acquisition opportunities and an extensive track record of building businesses in resource plays. Furthermore, we believe our ability to understand the geology, geophysics and reservoir parameters of the rock formations in the Delaware Basin will allow us to make prudent future acquisition decisions in order to grow our resource base and maximize stockholder value. |
• | Preserve financial flexibility to pursue organic and external growth opportunities. We carefully manage our liquidity and leverage levels by regularly monitoring cash flow, capital spending and debt capacity. We intend to maintain modest leverage levels to preserve operational and strategic flexibility as well as access to the capital markets. We expect to fund our growth with cash flow from operations, availability under our revolving credit facility and capital markets offerings when appropriate. We intend to allocate capital in a disciplined manner and proactively manage our cost structure to achieve our business objectives. We expect to maintain an active hedging program that seeks to reduce our exposure to lower commodity prices and protect our cash flow. |
Our Competitive Strengths
We believe that the following strengths will help us achieve our business goals:
• | Attractively positioned in the oil-rich core of the Southern Delaware Basin. Substantially all of our current leasehold acreage is located in the oil-rich southern portion of the Delaware Basin in Reeves, |
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Ward and Pecos counties. The majority of our properties are in Reeves County, which is the second most active county in the United States in horizontal drilling with 50 horizontal rigs running as of September 30, 2014. Since September 2013, the number of active horizontal rigs in Reeves County has increased by approximately 213%. We believe our multi-year, oil-weighted inventory of horizontal drilling locations provides attractive growth and return opportunities. As of September 30, 2014, our estimated reserves consisted of approximately 78% oil, 6% NGLs and 16% natural gas. The extensive original oil-in-place and other favorable geologic characteristics of the Southern Delaware Basin, along with the established vertical well control present across our acreage, give us a high degree of confidence in our current horizontal drilling program. |
• | Large horizontal drilling inventory across multiple pay zones. We have identified 1,232 undeveloped horizontal drilling locations in five zones across our acreage position in Reeves and Ward counties. In addition, we believe we will be able to identify additional horizontal locations as we conduct downspacing pilots, which were initiated in the fourth quarter of 2014. Of the initial 1,232 identified horizontal drilling locations, 69 are in the 3rd Bone Spring, 414 are in the Upper Wolfcamp A, 353 are in the Lower Wolfcamp A, 85 are in the Wolfcamp B and 311 are in the Wolfcamp C. Furthermore, the 2nd Bone Spring and Avalon Shale formations in the Delaware Basin may provide additional future opportunities as offset operators prove up and reduce development risk in those zones. |
• | Our acreage has been delineated across multiple zones. Our 35 horizontal wells (33 of which we operate) span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, offset operators have continued to successfully drill horizontal wells across our five targeted zones in close proximity to our leasehold, further delineating our acreage position. |
• | Proven horizontal drilling expertise and technical acumen in the Delaware Basin. We believe our horizontal drilling experience targeting multiple pay zones in the Delaware Basin provides us with a competitive advantage. Our horizontal wells have performed in the top tier of Southern Delaware Basin operators measured on a peak 30-day average initial production rate per 1,000 lateral feet, based on data over the last twelve months from the Texas Railroad Commission. Over the last nine months, we have reduced drilling days from 57 to 41 days, and we expect improvements will continue. Additionally, we believe we have drilled the most Wolfcamp C horizontal wells in the Southern Delaware Basin, demonstrating our horizontal drilling leadership in our area of the Basin. Furthermore, our technical team has extensive experience developing resources using horizontal drilling in the Permian, Bakken and Niobrara plays over the last decade and has leveraged this experience to enhance the development of our Delaware Basin acreage. |
• | High degree of operational control. Our significant operational control allows us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility allows us to efficiently develop our current acreage. In addition, we believe communication and data exchange with offset operators will reduce the risks associated with drilling the multiple horizontal zones of our acreage. We also believe our significant level of operational control will enable us to implement drilling optimization strategies, such as pad drilling, continued reduction of spud-to-rig-release days and downspacing. We have approximately 48% of our total net acreage either held by production or under continuous drilling provisions. We believe the substantial majority of our operated Reeves and Ward county net acreage will be held by production by early 2016. |
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• | Experienced and incentivized management team. With an average of 26 years of industry experience, our senior management team has a proven track record of building and running successful businesses focused on the development and acquisition of oil and gas properties. We believe our team’s experience and expertise in horizontal drilling and completions in unconventional formations across multiple resource plays provides us with a distinct competitive advantage. Additionally, our management team has a significant indirect economic interest in us through the ownership of incentive units, which provides a meaningful incentive to increase the value of our business for the benefit of all stockholders. |
• | Conservatively capitalized balance sheet and strong liquidity profile. After giving effect to this offering and the use of proceeds therefrom, we expect to have no outstanding borrowings under our revolving credit facility and approximately $ million of cash on the balance sheet. We believe the approximately $ million of availability on our revolving credit facility, cash on hand and cash flow from operations will provide us with sufficient liquidity to execute on our current capital program. |
Formation Transactions
Centennial OpCo. Centennial OpCo (formerly named Atlantic Energy Holdings, LLC) is an independent oil and natural gas company formed on August 30, 2012 by its management members, third-party investors and an affiliate of NGP. Centennial OpCo commenced operations following the acquisition of working interests in oil and gas properties located in Reeves, Ward and Pecos counties in West Texas, targeting the Delaware Basin portion of the Permian Basin. At the time of that acquisition, Celero also owned a working interest in the majority of these same properties.
Subsequently, in April 2014, NGP contributed its membership interests in Centennial OpCo to Centennial Resource Development, LLC (“Centennial HoldCo”), which was formed by NGP and current members of our management. Centennial HoldCo is a holding company with no independent operations apart from its ownership interests in Centennial OpCo. On or before August 2014, all of the other members of Centennial OpCo (including its management members) sold their membership interests in Centennial OpCo to Centennial OpCo or Centennial HoldCo for cash. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo.
Celero. Celero is an independent oil and natural gas company that was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Celero was formed by its general partner, Celero Energy Management, LLC, its management team and NGP.
Beginning in 2006, through a series of acquisitions of undeveloped acreage and producing properties as well as through development drilling and other activities, Celero focused on a number of project areas in the Permian Basin, including (i) oil and gas properties primarily located in Howard County, Texas and Lea County, New Mexico that were subsequently sold to Resolute Energy Corporation (“Resolute”) in December 2012 (the “Resolute Disposition”), (ii) oil and gas properties in Chaves County, New Mexico pursuant to which Celero pursued a tertiary recovery project utilizing CO2 to increase production on such properties that were subsequently sold to an unrelated third party in May 2014 (the “CO2 Project Disposition”) and (iii) oil and gas properties located in Reeves, Ward and Pecos counties in West Texas targeting the Delaware Basin portion of the Permian Basin, a portion of which was sold in October 2012 (the “Wolfbone Disposition” and, together with the Resolute Disposition and the CO2 Project Disposition, the “Dispositions”). Following the Dispositions, Celero owned non-operated interests in oil and natural gas properties in the Delaware Basin in which Centennial OpCo also has a working interest and substantially all of which are operated by Centennial OpCo.
The Combination. On October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo (the “Combination”).
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Immediately following the completion of the Combination, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
Our Corporate Reorganization. Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, each of Centennial HoldCo and Celero will contribute all of their interests in Centennial OpCo to Centennial Resource Development, Inc., the issuer of common stock in this offering, in exchange for shares of common stock in Centennial Resource Development, Inc. As a result, Centennial Resource Development, Inc. will become the holding company for Centennial OpCo.
Our Ownership and Organizational Structure
Following our corporate reorganization, our existing investors (the “Existing Investors”) will consist of the following:
Number of Shares Owned Before this Offering | Shares to be Offered in this Offering (1) | Number of Shares Owned After this Offering (1) | ||||
Existing Investor Name: | ||||||
Centennial Resource Development, LLC | ||||||
Celero Energy Company, LP | ||||||
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Total | ||||||
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(1) | Assumes no exercise of the underwriters’ option to purchase additional shares of our common stock. |
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Ownership Structure After Giving Effect to Our Corporate Reorganization and this Offering
The following diagram indicates our ownership structure after giving effect to our corporate reorganization and this offering (assuming that the underwriters’ option to purchase additional shares is not exercised).
Risk Factors
Investing in our common stock involves risks that include the speculative nature of oil and natural gas development and production, competition, volatile oil, NGL and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” for an explanation of these risks before investing in our 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 common stock and a loss of all or part of your investment:
• | The volatility of oil, NGL and natural gas prices due to factors beyond our control 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 acquisition projects require substantial capital that we may be unable to obtain, which could lead to a decline in our ability to access or grow production and reserves. |
• | Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves. |
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• | Our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas, making us vulnerable to risks associated with a concentration of operations in a single geographic area. |
• | Development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced. |
• | Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas reserves. |
• | We depend upon several significant purchasers for the sale of most of our oil, NGL and natural gas production. The loss of one or more of these purchasers could adversely affect our revenues in the short-term. |
• | Our operations are subject to operational hazards for which we may not be adequately insured. |
• | Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion. |
• | Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive and adversely affect the feasibility of conducting our operations. |
• | Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations and financial condition. |
• | The Existing Investors collectively hold all of our common stock prior to this offering and will hold approximately % of our common stock after this offering, assuming no exercise of the underwriters’ option to purchase additional shares of our common stock, and their interests may conflict with yours. |
• | We expect to be a “controlled company” within the meaning of the rules of the New York Stock Exchange (“NYSE”) and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements. |
Emerging Growth Company
We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:
• | 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 of 2002; |
• | provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations; |
• | comply with any new requirements adopted by the Public Company Accounting Oversight Board (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; |
• | provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on the executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or |
• | obtain stockholder approval of any golden parachute payments not previously approved. |
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We will cease to be an emerging growth company upon the earliest of:
• | the last day of the fiscal year in which we have $1.0 billion or more in annual revenues; |
• | 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); |
• | the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or |
• | the last day of the fiscal year following the fifth anniversary of our initial public offering. |
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 (the “Securities Act”), for complying with new or revised accounting standards, but we hereby irrevocably opt out of the extended transaction period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.
Principal Executive Offices and Internet Address
Our principal executive offices are located at 1401 17th Street, Suite 1000, Denver, Colorado 80202, and our telephone number at that address is (720) 441-5515. We also lease additional office space in Midland, Texas.
Our website address is . We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
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The Offering
Issuer | Centennial Resource Development, Inc. |
Common stock offered by us | shares. |
Common stock offered by the selling stockholders | shares (or shares, if the underwriters exercise in full their option to purchase additional shares). |
Common stock outstanding after this offering | shares. |
Common stock owned by the Existing Investors after this Offering | shares (or shares, if the underwriters exercise in full their option to purchase additional shares). |
Option to purchase additional shares | The selling stockholders have granted the underwriters a 30- day option to purchase up to an aggregate of additional shares of our common stock to the extent the underwriters sell more than shares of common stock in this offering. |
Use of proceeds | We expect to receive approximately $ million of net proceeds, 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. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million. |
We intend to use a portion of the net proceeds from this offering to fully repay outstanding indebtedness under our revolving credit facility and the remaining net proceeds for general corporate purposes, including to fund our 2015 capital expenditures. As of November 1, 2014, we had $43 million of outstanding borrowings under our revolving credit facility. We will not receive any proceeds from the sale of shares by the selling stockholders. Please read “Use of Proceeds.” |
Dividend policy | We do not anticipate paying any cash dividends on our common stock. In addition, our credit agreement places certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy.” |
Directed share program | The underwriters have reserved for sale at the initial public offering price up to % of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, director nominees, business associates and related persons who have expressed an interest in purchasing common stock in this offering. We do not know if these persons will choose to purchase all or any |
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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.” |
Listing and trading symbol | We intend to apply to list our common stock on the NYSE under the symbol “CDEV.” |
Risk factors | You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock. |
The information above does not include shares of common stock reserved for issuance pursuant to our equity incentive plan.
Except as otherwise indicated, all information contained in this prospectus assumes:
• | no exercise of the underwriters’ option to purchase additional shares of our common stock; and |
• | that the initial public offering price of the shares of our common stock will be $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus). |
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Summary Historical and Pro Forma Financial Data
Centennial Resource Development, Inc. was formed in October 2014 and does not have historical financial operating results. The following table shows summary historical consolidated and combined financial data of our accounting predecessor, which reflects the consolidated and combined results of Centennial OpCo and Celero, and summary unaudited pro forma consolidated and combined financial data of Centennial Resource Development, Inc. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor,” our future results of operations will not be comparable to the historical results of our predecessor.
The summary historical consolidated and combined financial data of our predecessor as of and for the years ended December 31, 2013 and 2012 were derived from the audited historical consolidated and combined financial statements of our predecessor included elsewhere in this prospectus. The summary historical interim consolidated and combined financial data of our predecessor as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from the unaudited interim consolidated and combined financial statements of our predecessor included elsewhere in this prospectus.
The summary unaudited pro forma consolidated and combined financial data of Centennial Resource Development, Inc. as of and for the six months ended June 30, 2014 and for the year ended December 31, 2013 were derived from the unaudited pro forma consolidated and combined financial statements included elsewhere in this prospectus. The pro forma consolidated and combined financial data has been prepared to give effect to (i) the Dispositions, which are described under “—Formation Transactions—Celero,” (ii) the corporate reorganization described under “—Formation Transactions—Our Corporate Reorganization” and (iii) this offering and the application of net proceeds from this offering as if they had taken place on June 30, 2014, in the case of the unaudited pro forma consolidated and combined balance sheet data, and on January 1, 2013, in the case of the pro forma consolidated and combined statement of operations data for the six months ended June 30, 2014 and the year ended December 31, 2013.
You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Recent and Formation Transactions,” the historical consolidated and combined financial statements of our predecessor and the unaudited pro forma consolidated and combined financial statements of Centennial Resource Development, Inc. included elsewhere in this prospectus.
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Among other things, those historical consolidated and combined financial statements include more detailed information regarding the basis of presentation for the following information.
Our Predecessor | Pro Forma | |||||||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||||||||||
Statement of Operations Data | ||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Oil sales | $ | 56,295 | $ | 21,810 | $ | 65,863 | $ | 56,207 | $ | $ | ||||||||||||||
Natural gas and NGL sales | 6,283 | 1,805 | 4,907 | 4,051 | ||||||||||||||||||||
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Total revenues | $ | 62,578 | $ | 23,615 | $ | 70,770 | $ | 60,258 | $ | $ | ||||||||||||||
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Operating expenses: | ||||||||||||||||||||||||
Lease operating expenses | $ | 8,156 | $ | 8,489 | $ | 19,193 | $ | 22,580 | $ | $ | ||||||||||||||
Severance and ad valorem taxes | 3,312 | 1,476 | 4,153 | 4,275 | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,146 | 10,624 | 29,285 | 21,035 | ||||||||||||||||||||
Exploration and abandonment expenses | 2 | 98 | 8,561 | 10,381 | ||||||||||||||||||||
General and administrative expenses(1) | 22,683 | 6,830 | 16,842 | 6,939 | ||||||||||||||||||||
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Total operating expenses | $ | 63,299 | $ | 27,517 | $ | 78,034 | $ | 65,210 | $ | $ | ||||||||||||||
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(Loss) gain on sale of oil and natural gas properties | (2,390 | ) | 1,049 | 16,756 | 36,407 | |||||||||||||||||||
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Total operating (loss) income | $ | (3,111 | ) | $ | (2,853 | ) | $ | 9,492 | $ | 31,455 | $ | $ | ||||||||||||
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Other (expense) income: | ||||||||||||||||||||||||
Interest expense | $ | (599 | ) | $ | (153 | ) | $ | (513 | ) | $ | (1,084 | ) | ||||||||||||
(Loss) gain on derivative instruments | (6,164 | ) | (1,184 | ) | (4,410 | ) | 2,868 | |||||||||||||||||
Other income (expense) | 239 | (183 | ) | 122 | (394 | ) | ||||||||||||||||||
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Total other (expense) income | $ | (6,524 | ) | $ | (1,520 | ) | $ | (4,801 | ) | $ | 1,390 | $ | $ | |||||||||||
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Loss before taxes | (9,635 | ) | (4,373 | ) | 4,691 | 32,845 | ||||||||||||||||||
Income tax expense | (1,027 | ) | (447 | ) | (1,079 | ) | (563 | ) | ||||||||||||||||
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Net (loss) income | $ | (10,662 | ) | $ | (4,820 | ) | $ | 3,612 | $ | 32,282 | $ | $ | ||||||||||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | (1 | ) | (6 | ) | — | |||||||||||||||||
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Net (loss) income attributable to predecessor | $ | (10,660 | ) | $ | (4,819 | ) | $ | 3,618 | $ | 32,282 | $ | $ | ||||||||||||
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Per Share Data (unaudited): | ||||||||||||||||||||||||
Net earnings (loss) per common share: | ||||||||||||||||||||||||
Basic and diluted | $ | $ | ||||||||||||||||||||||
Weighted average common shares outstanding: | ||||||||||||||||||||||||
Basic and diluted |
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Our Predecessor | Pro Forma | |||||||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||
Net cash provided by operating activities | $ | 53,943 | $ | 2,811 | $ | 13,416 | $ | 20,359 | ||||||||||||||||
Net cash used in investing activities | (28,602 | ) | (63,005 | ) | (136,517 | ) | (46,395 | ) | ||||||||||||||||
Net cash (used in) provided by financing activities | (12,502 | ) | 44,043 | 118,742 | 72,523 | |||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||
Adjusted EBITDAX (unaudited)(2) | $ | 38,899 | $ | 921 | $ | 17,262 | $ | 13,596 | $ | $ |
(1) | General and administrative expenses for the six months ended June 30, 2014 includes $12.4 million of incentive compensation recorded due to the achievement of certain performance criteria associated with our predecessor’s incentive units and severance payments of approximately $2.2 million to terminated employees of our predecessor. |
(2) | Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see “—Non-GAAP Financial Measure” below. |
Our Predecessor | Pro Forma | |||||||||||||||
June 30, 2014 | December 31, | June 30, 2014 | ||||||||||||||
2013 | 2012 | |||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
(In thousands) | ||||||||||||||||
Balance Sheet Data: | ||||||||||||||||
Cash and cash equivalents | $ | 55,022 | $ | 42,183 | $ | 46,542 | $ | |||||||||
Cash held in escrow | — | 5,000 | 34,500 | $ | ||||||||||||
Other current assets | 17,923 | 19,132 | 16,025 | |||||||||||||
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Total current assets | 72,945 | 66,315 | 97,067 | |||||||||||||
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Total oil and natural gas properties, other property and equipment, net | 431,597 | 357,541 | 248,203 | |||||||||||||
Assets held for sale | — | 47,480 | — | |||||||||||||
Other long-term assets | 701 | 749 | 1,185 | |||||||||||||
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Total assets | $ | 505,243 | $ | 472,085 | $ | 346,455 | $ | |||||||||
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Current liabilities | $ | 72,517 | $ | 46,169 | $ | 42,404 | $ | |||||||||
Long-term debt | 75,000 | 29,000 | — | |||||||||||||
Other long-term liabilities | 4,690 | 6,369 | 7,071 | |||||||||||||
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Total liabilities | 152,207 | 81,538 | 49,475 | |||||||||||||
Owners’ equity | 353,036 | 389,859 | 296,980 | |||||||||||||
Noncontrolling interest in unconsolidated subsidiary | — | 688 | — | |||||||||||||
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Total equity | 353,036 | 390,547 | 296,980 | |||||||||||||
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Total liabilities and owners’ equity | $ | 505,243 | $ | 472,085 | $ | 346,455 | $ | |||||||||
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Non-GAAP Financial Measure
Adjusted EBITDAX 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 EBITDAX as net income (loss) attributable to our predecessor before interest expense, income taxes, depreciation, depletion, amortization and accretion of asset retirement obligations, exploration and abandonment expenses, prepayment premium on extinguishment of debt, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivatives and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation and (gains) losses from the sale of oil and natural gas properties. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles (“GAAP”).
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX 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 EBITDAX 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 EBITDAX 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 EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or in line with debt covenant definitions.
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The following table presents a reconciliation of Adjusted EBITDAX to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP.
Our Predecessor | Pro Forma | |||||||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Adjusted EBITDAX Reconciliation to Net (Loss) Income: | ||||||||||||||||||||||||
Net (loss) income attributable to the predecessor | $ | (10,660 | ) | $ | (4,819 | ) | $ | 3,618 | $ | 32,282 | $ | $ | ||||||||||||
Interest expense | 599 | 153 | 513 | 1,084 | ||||||||||||||||||||
Income tax expense | 1,027 | 447 | 1,079 | 563 | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,146 | 10,624 | 29,285 | 21,035 | ||||||||||||||||||||
Exploration and abandonment expenses | 2 | 98 | 8,561 | 10,381 | ||||||||||||||||||||
Prepayment premium on extinguishment of debt | — | — | — | — | ||||||||||||||||||||
Loss (gain) on derivative instruments | 6,164 | 1,184 | 4,410 | (2,868 | ) | |||||||||||||||||||
Net cash payments on settled derivatives | (1,478 | ) | (5,567 | ) | (12,651 | ) | (12,474 | ) | ||||||||||||||||
Premiums paid for put options that settled during the period(1) | (711 | ) | (150 | ) | (797 | ) | — | |||||||||||||||||
Impairments of oil and natural gas properties | — | — | — | — | ||||||||||||||||||||
Non-cash equity based compensation | 12,420 | — | — | — | ||||||||||||||||||||
Loss (gain) on sale of oil and natural gas properties | 2,390 | (1,049 | ) | (16,756 | ) | (36,407 | ) | |||||||||||||||||
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Adjusted EBITDAX (unaudited) | $ | 38,899 | $ | 921 | $ | 17,262 | $ | 13,596 | $ | $ | ||||||||||||||
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(1) | Represents premiums paid at inception for put options that settled during the respective period. |
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Summary Historical Reserve and Historical and Pro Forma Operating Data
The following tables present, as of the dates indicated, summary data with respect to our estimated combined net proved oil and natural gas reserves and combined operating data.
The reserve estimates attributable to our properties as of September 30, 2014 presented in the table below are based on a reserve report prepared by NSAI, our independent reserve engineers. All of these reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Oil and Natural Gas Data—Proved Reserves” in evaluating the material presented below.
As of September 30, 2014(1) | ||||
Proved Reserves: | ||||
Oil (MBbls) | 17,038 | |||
NGLs (MBbls) | 1,273 | |||
Natural gas (MMcf) | 20,669 | |||
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Total proved reserves (MBoe)(2) | 21,756 | |||
Proved Developed Reserves: | ||||
Oil (MBbls) | 6,779 | |||
NGLs (MBbls) | 618 | |||
Natural gas (MMcf) | 8,328 | |||
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Total proved developed reserves (MBoe)(2) | 8,786 | |||
Proved developed reserves as a percentage of total proved reserves | 40 | % | ||
Proved Undeveloped Reserves: | ||||
Oil (MBbls) | 10,258 | |||
NGLs (MBbls) | 655 | |||
Natural gas (MMcf) | 12,341 | |||
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Total proved undeveloped reserves (MBoe)(2) | 12,970 | |||
Oil and Natural Gas Prices: | ||||
Oil—NYMEX—WTI per Bbl | $ | 95.56 | ||
Natural gas—NYMEX—Henry Hub per MMBtu | $ | 4.24 |
(1) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. |
(2) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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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Our Predecessor | Pro Forma(1) | |||||||||||||||
Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||
(Unaudited) | ||||||||||||||||
Production and Operating Data: | ||||||||||||||||
Net Production Volumes: | ||||||||||||||||
Oil (MBbls) | 619 | 713 | ||||||||||||||
Natural gas and NGLs (MMcfe ) | 985 | 933 | ||||||||||||||
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Total (MBoe)(2) | 783 | 869 | ||||||||||||||
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Average net daily production (Boe/d) | 4,326 | 2,381 | ||||||||||||||
Average Sales Prices: | ||||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 90.95 | $ | 92.37 | $ | $ | ||||||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 88.56 | 74.63 | ||||||||||||||
Natural gas and NGLs (per Mcfe) | 6.38 | 5.26 | ||||||||||||||
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Total (per Boe) (excluding impact of cash settled derivatives) | 79.92 | 81.44 | ||||||||||||||
Total (per Boe) (after impact of cash settled derivatives) | 78.03 | 66.88 | ||||||||||||||
Average Unit Costs per Boe: | ||||||||||||||||
Lease operating expenses | $ | 10.42 | $ | 22.09 | $ | $ | ||||||||||
Severance and ad valorem taxes | 4.23 | 4.78 | ||||||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 37.22 | 33.70 | ||||||||||||||
Exploration and abandonment expenses | 0.00 | 9.85 | ||||||||||||||
General and administrative expenses(3)(4) | 28.97 | 19.38 |
(1) | Gives effect to the Dispositions, which are described under “—Formation Transactions—Celero.” |
(2) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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) | General and administrative expenses for the six months ended June 30, 2014 includes $12.4 million ($15.84 per Boe) of incentive compensation recorded due to the achievement of certain performance criteria associated with our predecessor’s incentive units and severance payments of $2.2 million ($2.81 per Boe) to terminated employees of our predecessor. |
(4) | Combined general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company. |
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Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.
Risks Related to Our Business
Oil, NGL 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 liquids-rich natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas 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 oil, NGLs and natural gas; |
• | the price and quantity of foreign imports; |
• | political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia; |
• | the ability of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
• | the level of global exploration, development and production; |
• | the level of global inventories; |
• | prevailing prices on local price indexes 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; |
• | the cost of exploring for, developing, producing and transporting reserves; |
• | weather conditions and other natural disasters; |
• | technological advances affecting energy consumption; |
• | the price and availability of alternative fuels; expectations about future commodity prices; and |
• | domestic, local and foreign governmental regulation and taxes. |
Lower commodity prices may 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 oil, NGLs and natural gas that we can produce economically.
If commodity prices decrease, a significant portion of our development and acquisition projects could become uneconomic. This may result in our having to make significant downward adjustments to 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.
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Our development and acquisition 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 ability to access or grow production and reserves.
The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to our development and acquisition projects. We currently estimate our 2015 capital budget for drilling, completion and recompletion activities and facilities costs will be approximately $ million, excluding leasing and other acquisitions. We expect to fund 2015 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and possibly through asset sales or additional capital markets 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, NGL 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 near-term capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.
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; |
• | our ability to acquire, locate and produce new reserves; and |
• | our ability to borrow under our revolving credit facility. |
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil, NGL 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 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 could materially and adversely affect our business, financial condition and results of operations.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include the following:
• | landing our wellbore in the desired drilling zone; |
• | staying in the desired drilling zone while drilling horizontally through the formation; |
• | running our casing the entire length of the wellbore; and |
• | being able to run tools and other equipment consistently through the horizontal wellbore. |
Risks that we face while completing our wells include the following:
• | the ability to fracture stimulate the planned number of stages; |
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• | the ability to run tools the entire length of the wellbore during completion operations; and |
• | the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage. |
The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
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 development, acquisition and production 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 develop or purchase 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.
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 (“GHGs”) 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; |
• | issues related to compliance with environmental regulations; |
• | environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures 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; and |
• | limitations in the market for oil and natural gas. |
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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 term loan and revolving credit facility, 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 would likely result in a reduction of our credit rating, which 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 agreement currently restricts 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.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our credit agreement contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:
• | incur additional indebtedness; |
• | make loans to others; |
• | make investments; |
• | merge or consolidate with another entity; |
• | make certain payments; |
• | hedge future production or interest rates; |
• | incur liens; |
• | sell assets; and |
• | engage in certain other transactions without the prior consent of the lenders. |
In addition, our credit agreement 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 agreement impose on us.
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A breach of any covenant in our credit agreement 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 our credit agreement 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.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually each April 1 and October 1 (and in 2015, on January 1 and July 1 as well). The credit agreement also allows, in 2016 and thereafter, for two borrowing base redeterminations, at our option or the option of the lenders, on January 1 and July 1. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. 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. Our borrowing base under our revolving credit facility was $80 million as of June 30, 2014. In August 2014, as part of our semi-annual redetermination process, our borrowing base was increased to $115 million, and as a result of the Combination, our borrowing base was further increased to $145 million in October 2014.
In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our derivative activities could result in financial losses or could reduce our earnings.
We enter into derivative instrument contracts for a portion of our oil production. As of June 30, 2014, we had entered into hedging contracts through June 2016 covering a total of 1,426 MBbls of our projected oil production. 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. |
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
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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 a material 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 the counterparty 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. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than we estimate and may be rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect production history, results of development, existing commodity prices and other factors.
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.
We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
We have leased or acquired approximately 40,500 net acres as of September 30, 2014, approximately 81% of which we operate. As of September 30, 2014, we were the operator on 653 of our 1,232 identified gross
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horizontal drilling locations. We will have limited ability to exercise influence over the operations of the drilling locations operated by our partners. The success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
• | the timing and amount of capital expenditures; |
• | the operator’s expertise and financial resources; |
• | the approval of other participants in drilling wells; |
• | the selection of technology; and |
• | the rate of production of reserves, if any. |
This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.
Our identified drilling locations are scheduled out 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 drilling 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 drilling 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 drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
As of September 30, 2014, we had identified 1,232 horizontal drilling locations on our acreage based on approximately 880 foot spacing between wells with five to six wells per zone per 640 acres, consisting primarily of approximately 4,400 foot laterals. Additionally, based on our evaluation of applicable geologic and engineering data as of September 30, 2014, we had 34 identified vertical drilling locations on 40-acre spacing. As a result of the limitations described above, we may be unable to drill many of our identified locations. 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 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.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
We estimate that 48% of our net acreage is currently held by production or is being held under continuous drilling provisions. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions of the leases or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural
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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.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, NGLs and natural gas. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
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. Drought conditions have persisted in Texas over the past several years. 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, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.
Our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in 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 Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At September 30, 2014, 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, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, NGLs or natural gas.
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 marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by owned and third party gathering systems. Our purchasers then transport the oil by truck or pipeline for transportation. Our natural gas production is generally transported by gathering lines from the wellhead to a gas processing facility. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
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We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we 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 PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of September 30, 2014, 60% of our total estimated proved reserves were classified as proved undeveloped. 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 value of our estimated PUDs 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 PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.
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 write-down 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 exploration and development 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 our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, 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 materially and adversely affected.
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 natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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We depend upon several significant purchasers for the sale of most of our oil, NGL and natural gas production.
We normally sell our production to a relatively small number of customers, as is customary in our business. For the six months ended June 30, 2014 and the year ended December 31, 2013, Plains Marketing, L.P. accounted for 79% and 72%, respectively, of our total revenue. During such periods, no other purchaser accounted for 10% or more of our revenue. For the year ended December 31, 2012, four purchasers accounted for 10% or more of our revenue: Genesis Crude Oil, L.P. (35%), Plains Marketing, L.P. (20%), Enterprise Crude Oil (12%) and LPC Crude Oil, Inc. (10%). The loss of any of these purchasers could materially and adversely affect our revenues in the short-term.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
Our operations are 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 connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. 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.
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.
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Our development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
• | environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; |
• | abnormally pressured formations; |
• | mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; |
• | fires, explosions and ruptures of pipelines; |
• | personal injuries and death; |
• | natural disasters; and |
• | terrorist attacks targeting oil and natural gas related facilities and infrastructure. |
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; |
• | 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. |
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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 businesses that complement or expand our current business. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
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 credit agreement imposes certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our oil and natural gas development and transportation 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 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. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well as injunctions limiting or prohibiting our activities. These regulations could change to our detriment. 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. Such costs could have a material adverse effect on our business, financial condition and results of operations.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. These land use restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.
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Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, development of, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.
Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, discharges of oil, NGLs, natural gas and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of 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 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. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire. Equipment 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.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act (“NGPA”) 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 operations to FERC annual reporting and posting 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. 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 GHGs 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 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, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction 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
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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 natural gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.
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. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, in 2013 the Obama administration announced its Climate 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 natural gas industry. 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. 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 a material adverse effect on our 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 important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in May 2013, the Bureau of Land Management of the U.S. Department of the Interior published a revised proposed rule that would impose requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, as well as wellbore integrity and handling of flowback water. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.
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. For example, the EPA is developing effluent limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose such standards by late 2014.
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Further, in April 2012, the EPA published final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are 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”) for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. The EPA received numerous requests for reconsideration of these rules and court challenges were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, in September 2013 the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.
Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources and expects to make the final report 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 and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
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 issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments 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 development activities, and perhaps even be precluded from drilling wells.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
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. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over
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the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. 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.
Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.
Our predecessors were formed in 2006 and 2012. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
In addition, 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.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of 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. For example, as of June 30, 2014, outstanding borrowings subject to variable interest rates were approximately $75 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $0.75 million, assuming the $75 million of debt was outstanding for the full year. Recent and continuing 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.
We may be subject to risks in connection with acquisitions of properties.
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; |
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• | operating costs; and |
• | potential environmental and other liabilities. |
The accuracy of these assessments is inherently uncertain. 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 fully assess 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.
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 2015 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and natural 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 natural 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 natural 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 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, 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. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in 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 activities that could have a material and 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 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 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 and 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 and 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.
The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil and natural gas reserves.
Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.
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,
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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.
Risks Related to this Offering and Our Common Stock
The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:
• | institute a more comprehensive compliance function; |
• | comply with rules promulgated by the NYSE; |
• | continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; |
• | establish new internal policies, such as those relating to insider trading; and |
• | involve and retain to a greater degree outside counsel and accountants in the above activities. |
Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls 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. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2020. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our
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reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.
Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our 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 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 common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholders and representative of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our 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 common stock; |
• | sales of our common stock by us, the selling stockholders or other stockholders, 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 stockholders; |
• | 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 described 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
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price of our 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.
NGP has the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.
Upon completion of this offering, NGP, through the Existing Investors, will beneficially own approximately % of our outstanding common stock (or approximately % if the underwriters’ option to purchase additional shares of our common stock is exercised in full). As a result, NGP will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of NGP with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, NGP would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of NGP. These directors’ duties as employees of NGP may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. NGP’s concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, two of our directors (Messrs. Aneed and Hayes) and our director nominee (Chris Carter) are Managing Directors of NGP, which is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”
NGP and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP to benefit from corporate opportunities that might otherwise be available to us.
Our governing documents will provide that NGP and its affiliates (including portfolio investments of NGP and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:
• | permit NGP and its affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and |
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• | provide that if NGP or its affiliates or any director or officer of one of our affiliates, NGP or their respective affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us. |
NGP or its 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, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, NGP and its affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to NGP or its 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—Corporate Opportunities.”
NGP is an established participant in the oil and natural gas industry and has resources greater than ours, which may make it more difficult for us to compete with NGP with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and NGP, on the other hand, will be resolved in our favor. As a result, competition from NGP and its affiliates could adversely impact our results of operations.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder 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 stockholders, including:
• | limitations on the removal of directors; |
• | limitations on the ability of our stockholders to call special meetings; |
• | establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; |
• | 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 stockholders at stockholder meetings. |
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
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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 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 common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2014 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 do not intend to pay cash dividends on our common stock, and our credit agreement places 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 common stock appreciates.
We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, our credit agreement places 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 common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.
Future sales of our common stock in the public market, or the perception that such sales may occur, 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.
We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we and the selling stockholders are selling in this offering and shares that the selling stockholders 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, and assuming full exercise of the underwriters’ option to purchase additional shares, the Existing Investors will own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting,” but may be sold into the market in the future. The Existing Investors will be party to a registration rights agreement, which 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 “Certain Relationships and Related Party Transactions—Registration Rights Agreement” and “Shares Eligible for Future Sale.”
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In connection with this offering, we intend to file a registration statement with the SEC onForm S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement onForm S-8 will be available for resale immediately in the public market without restriction.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our 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 common stock.
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 common stock.
All of our directors and executive officers, certain of our stockholders and the selling stockholders have entered into lock-up agreements with respect to their 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. Barclays Capital Inc., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our amended and restated certificate of incorporation will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our 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 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 common stock.
We expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.
Upon completion of this offering, the Existing Investors will collectively beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:
• | a majority of the board of directors consist of independent directors; |
• | the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; |
• | the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and |
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• | there be an annual performance evaluation of the nominating and governance and compensation committees. |
These requirements will not apply to us as long as we remain a controlled company. Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”
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 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.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
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CAUTIONARY STATEMENT 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 management’s 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.
Forward-looking statements may include statements about:
• | our business strategy; |
• | our reserves; |
• | our drilling prospects, inventories, projects and programs; |
• | our ability to replace the reserves we produce through drilling and property acquisitions; |
• | our financial strategy, liquidity and capital required for our development program; |
• | our realized oil and natural gas prices; |
• | the timing and amount of our future production of oil and natural gas; |
• | our hedging strategy and results; |
• | our future drilling plans; |
• | our competition and government regulations; |
• | our ability to obtain permits and governmental approvals; |
• | our pending legal or environmental matters; |
• | our marketing of oil and natural gas; |
• | our leasehold or business acquisitions; |
• | our costs of developing our properties; |
• | general economic conditions; |
• | credit markets; |
• | uncertainty regarding our future operating results; and |
• | our 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 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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We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares by the selling stockholders, including any proceeds from the underwriters’ exercise of their option to purchase additional shares.
We intend to use a portion of the net proceeds from this offering to fully repay outstanding indebtedness under our revolving credit facility and the remaining net proceeds for general corporate purposes, including to fund our 2015 capital expenditures. As of November 1, 2014, we had $43 million of outstanding borrowings under our revolving credit facility. Our revolving credit facility matures October 15, 2019 and bears interest at a variable rate, which was approximately % at , 2014. We also pay a commitment fee on unused amounts of our revolving credit facility ranging from 37.5 basis points to 50 basis points, depending on the percentage of the borrowing base utilized. The outstanding borrowings under our revolving credit facility were incurred to fund a portion of our 2014 capital expenditures and to finance our purchase of certain equity interests of Centennial OpCo (as described in “Recent and Formation Transactions—Corporate Formation Transactions—The Combination”). We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so in the future to fund our capital 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, we would use the additional net proceeds for general corporate purposes. If the proceeds decrease due to a lower initial public offering price, then we would first reduce by a corresponding amount the net proceeds directed to general corporate purposes and then, if necessary, the net proceeds directed to fully repay outstanding borrowings under our revolving credit facility.
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We have never declared or paid, and do not anticipate declaring or paying, any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and 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 credit agreement places restrictions on our ability to pay cash dividends.
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The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2014:
• | on an actual basis for our predecessor; |
• | on a pro forma basis to give effect to the Dispositions, our corporate reorganization and the sale of shares of our 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 the application of the net proceeds from this offering as set forth under “Use of Proceeds.” |
The pro forma information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds” and our historical audited and unaudited consolidated and combined financial statements and the accompanying notes appearing elsewhere in this prospectus.
As of June 30, 2014 | ||||||||
Actual(1) | Pro Forma(2) | |||||||
(In thousands, except number of shares and par value) | ||||||||
Cash and cash equivalents | $ | 55,022 | $ | |||||
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Long-term debt, including current maturities: | ||||||||
Revolving credit facility(3) | 75,000 | |||||||
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Total indebtedness | $ | 75,000 | $ | |||||
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Owners’ equity | $ | 353,036 | $ | |||||
Stockholders’ equity: | ||||||||
Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, shares issued and outstanding, pro forma | — | |||||||
Additional paid-in capital | — | |||||||
Accumulated deficit | — | |||||||
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Total stockholders’ equity | $ | 353,036 | $ | |||||
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Total capitalization | $ | 428,036 | $ | |||||
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(1) | Centennial Resource Development, Inc. was incorporated in October 2014. The data in this table has been derived from the historical consolidated and combined 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 increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $ million, $ million and $ million, respectively, 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 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 increase (decrease) additional paid-in capital, total stockholders’ equity and total capitalization by approximately $ million, $ million and $ million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. |
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(3) | As of June 30, 2014, the borrowing base was $80 million, the outstanding amount totaled $75 million, and we were able to incur approximately $5 million of additional indebtedness under our revolving credit facility. As of June 30, 2014 we had a letter of credit of $50,000 outstanding under our revolving credit facility. On October 15, 2014, Centennial OpCo entered into an amended and restated credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders pursuant to which, among other things, our borrowing base was increased to $145 million, and we obtained a $65 million senior secured term loan that matures on April 15, 2017. In addition to our $65 million term loan, as of November 1, 2014, we had $43 million outstanding under our revolving credit facility and $300,000 of letters of credit outstanding. After giving effect to our corporate reorganization, the sale of shares of our common stock in this offering and the application of the anticipated net proceeds of this offering, we expect to have $ million of available borrowing capacity under our revolving credit facility. |
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Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our common stock for accounting purposes. Our net tangible book value as of June 30, 2014, after giving pro forma effect to the Combination, was approximately $ million, or $ per share.
Pro forma net tangible book value per share is determined by dividing our pro forma net tangible book value by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the Combination. Assuming an initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the Combination and the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of June 30, 2014 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 stockholders and an immediate dilution to new investors purchasing shares in this offering of $ per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering:
Assumed initial public offering price per share | $ | |||||
Pro forma net tangible book value per share as of June 30, 2014 (after giving effect to the Combination) | ||||||
Increase per share attributable to new investors in this offering | ||||||
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As adjusted pro forma net tangible book value per share (after giving effect to the Combination and this offering) | ||||||
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Dilution in pro forma net tangible book value per share to new investors in this offering | $ | |||||
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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 increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $ and increase (decrease) the dilution to new investors in this offering by $ per share, assuming 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.
The following table summarizes, on an adjusted pro forma basis as of June 30, 2014, the total number of shares of common stock owned by existing stockholders and to be owned by new investors at $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, and the total consideration paid and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , the midpoint of the price range set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.
Shares Acquired | Total Consideration | Average Price Per Share | ||||||||||||||||
Number | Percent | Amount | Percent | |||||||||||||||
Existing stockholders | % | $ | % | $ | ||||||||||||||
New investors in this offering | ||||||||||||||||||
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Total | 100 | % | $ | 100 | % | $ | ||||||||||||
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The data in the table excludes shares of common stock reserved for issuance under our equity incentive plan (which amount may be increased each year in accordance with the terms of the plan). 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 common stock.
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SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED AND COMBINED
FINANCIAL DATA
The following table shows selected historical and pro forma consolidated and combined financial data of our accounting predecessor and selected unaudited pro forma consolidated and combined financial data of Centennial Resource Development, Inc. for the periods and as of the dates indicated. Our accounting predecessor reflects the consolidated and combined results of Centennial OpCo and Celero. For more information regarding our predecessor, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Predecessor and Centennial Resource Development, Inc.”
The selected historical consolidated and combined financial data of our predecessor as of and for the years ended December 31, 2013 and 2012 were derived from the audited historical consolidated and combined financial statements of our predecessor included elsewhere in this prospectus. The selected historical interim consolidated and combined financial data of our predecessor as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from the unaudited interim consolidated and combined financial statements of our predecessor included elsewhere in this prospectus.
The selected unaudited pro forma consolidated and combined financial data of Centennial Resource Development, Inc. as of and for the six months ended June 30, 2014 and for the year ended December 31, 2013 were derived from the unaudited pro forma consolidated and combined financial statements included elsewhere in this prospectus. The pro forma consolidated and combined financial data has been prepared to give effect to (i) the Dispositions, (ii) the corporate reorganization described under “Recent and Formation Transactions—Corporate Formation Transactions—Our Corporate Reorganization” and (iii) this offering and the application of net proceeds from this offering as if they had taken place on June 30, 2014, in the case of the unaudited pro forma combined balance sheet data, and on January 1, 2013, in the case of the pro forma combined statement of operations data for the six months ended June 30, 2014 and the year ended December 31, 2013.
Our historical results are not necessarily indicative of future operating results. The selected consolidated and combined financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical consolidated and combined financial statements of our predecessor and the unaudited pro forma consolidated and combined financial statements of Centennial Resource Development, Inc. included elsewhere in this prospectus.
Our Predecessor | Pro Forma | |||||||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||||||||||
Statement of Operations Data | ||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Oil sales | $ | 56,295 | $ | 21,810 | $ | 65,863 | $ | 56,207 | $ | $ | ||||||||||||||
Natural gas and NGL sales | 6,283 | 1,805 | 4,907 | 4,051 | ||||||||||||||||||||
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| |||||||||||||
Total revenues | $ | 62,578 | $ | 23,615 | $ | 70,770 | $ | 60,258 | $ | $ | ||||||||||||||
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Operating expenses: | ||||||||||||||||||||||||
Lease operating expenses | $ | 8,156 | $ | 8,489 | $ | 19,193 | $ | 22,580 | ||||||||||||||||
Severance and ad valorem taxes | 3,312 | 1,476 | 4,153 | 4,275 | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,146 | 10,624 | 29,285 | 21,035 | ||||||||||||||||||||
Exploration and abandonment expenses | 2 | 98 | 8,561 | 10,381 |
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Our Predecessor | Pro Forma | |||||||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||||||||||
General and administrative expenses(1) | 22,683 | 6,830 | 16,842 | 6,939 | ||||||||||||||||||||
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| |||||||||||||
Total operating expenses | $ | 63,299 | $ | 27,517 | $ | 78,034 | $ | 65,210 | $ | $ | ||||||||||||||
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(Loss) gain on sale of oil and natural gas properties | (2,390 | ) | 1,049 | 16,756 | 36,407 | |||||||||||||||||||
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Total operating (loss) income | $ | (3,111 | ) | $ | (2,853 | ) | $ | 9,492 | $ | 31,455 | $ | �� | $ | |||||||||||
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Other (expense) income: | ||||||||||||||||||||||||
Interest expense | $ | (599 | ) | $ | (153 | ) | $ | (513 | ) | $ | (1,084 | ) | ||||||||||||
(Loss) gain on derivative instruments | (6,164 | ) | (1,184 | ) | (4,410 | ) | 2,868 | |||||||||||||||||
Other income (expense) | 239 | (183 | ) | 122 | (394 | ) | ||||||||||||||||||
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Total other (expense) income | $ | (6,524 | ) | $ | (1,520 | ) | $ | (4,801 | ) | $ | 1,390 | $ | $ | |||||||||||
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Loss before taxes | (9,635 | ) | (4,373 | ) | 4,691 | 32,845 | ||||||||||||||||||
Income tax expense | (1,027 | ) | (447 | ) | (1,079 | ) | (563 | ) | ||||||||||||||||
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Net (loss) income | $ | (10,662 | ) | $ | (4,820 | ) | $ | 3,612 | $ | 32,282 | $ | $ | ||||||||||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | (1 | ) | (6 | ) | — | |||||||||||||||||
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Net (loss) income attributable to predecessor | $ | (10,660 | ) | $ | (4,819 | ) | $ | 3,618 | $ | 32,282 | $ | $ | ||||||||||||
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Per Share Data (unaudited): | ||||||||||||||||||||||||
Net earnings (loss) per common share: | ||||||||||||||||||||||||
Basic and diluted | $ | $ | ||||||||||||||||||||||
Weighted average common shares outstanding: | ||||||||||||||||||||||||
Basic and diluted | ||||||||||||||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||
Net cash provided by operating activities | $ | 53,943 | $ | 2,811 | $ | 13,416 | $ | 20,359 | ||||||||||||||||
Net cash used in investing activities | (28,602 | ) | (63,005 | ) | (136,517 | ) | (46,395 | ) | ||||||||||||||||
Net cash (used in) provided by financing activities | (12,502 | ) | 44,043 | 118,742 | 72,523 | |||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||
Adjusted EBITDAX (unaudited)(2) | $ | 38,899 | $ | 921 | $ | 17,262 | $ | 13,596 | $ | $ |
(1) | General and administrative expenses for the six months ended June 30, 2014 includes $12.4 million ($15.84 per Boe) of incentive compensation recorded due to the achievement of certain performance criteria associated with our predecessor’s incentive units and severance payments of approximately $2.2 million ($2.81 per Boe) to terminated employees of our predecessor. |
(2) | Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see “Prospectus Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measure.” |
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Our Predecessor | Pro Forma | |||||||||||||||
June��30, 2014 | December 31, | June 30, 2014 | ||||||||||||||
2013 | 2012 | |||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
(In thousands) | ||||||||||||||||
Balance Sheet Data: | ||||||||||||||||
Cash and cash equivalents | $ | 55,022 | $ | 42,183 | $ | 46,542 | $ | |||||||||
Cash held in escrow | — | 5,000 | 34,500 | $ | ||||||||||||
Other current assets | 17,923 | 19,132 | 16,025 | |||||||||||||
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Total current assets | 72,945 | 66,315 | 97,067 | |||||||||||||
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Total oil and natural gas properties, other property and equipment, net | 431,597 | 357,541 | 248,203 | |||||||||||||
Assets held for sale | — | 47,480 | — | |||||||||||||
Other long-term assets | 701 | 749 | 1,185 | |||||||||||||
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Total assets | $ | 505,243 | $ | 472,085 | $ | 346,455 | $ | |||||||||
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Current liabilities | $ | 72,517 | $ | 46,169 | $ | 42,404 | $ | |||||||||
Long-term debt | 75,000 | 29,000 | — | |||||||||||||
Other long-term liabilities | 4,690 | 6,369 | 7,071 | |||||||||||||
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Total liabilities | 152,207 | 81,538 | 49,475 | |||||||||||||
Owners’ equity | 353,036 | 389,859 | 296,980 | |||||||||||||
Noncontrolling interest in unconsolidated subsidiary | — | 688 | — | |||||||||||||
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Total equity | 353,036 | 390,547 | 296,980 | |||||||||||||
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Total liabilities and owners’ equity | $ | 505,243 | $ | 472,085 | $ | 346,455 | $ | |||||||||
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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 and Combined 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 Statement 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 Centennial Resource Development, Inc.
Centennial Resource Development, Inc. was formed in October 2014 and does not have historical financial operating results. Our accounting predecessor reflects the consolidated and combined results of (i) Centennial OpCo, which was formed in August 2012 to engage in the development and acquisition of both conventional and unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin, and (ii) Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. As a result of the Dispositions, which are discussed under “—Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor—Dispositions,” substantially all of our operations are now concentrated in the Delaware Basin in West Texas. On October 15, 2014, through the Combination, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo.
Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, each of Centennial HoldCo and Celero will contribute all of their interests in Centennial OpCo to Centennial Resource Development, Inc., the issuer of common stock in this offering, in exchange for shares of common stock in Centennial Resource Development, Inc. For more information on our corporate formation transactions, see “Recent and Formation Transactions—Corporate Formation Transactions.”
Overview
We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Substantially all of our properties are located in the oil-rich core of the Southern Delaware Basin, an area of heightened horizontal drilling activity by many operators. Our activities are focused on the horizontal development of our leasehold across five separate producing zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C.
Our Properties
Our properties consist of large, contiguous acreage blocks primarily in the Delaware Basin, a sub-basin of the Permian Basin, in Reeves, Ward and Pecos counties in West Texas. As of September 30, 2014, we had interests in 111 gross (62 net) producing wells across our properties, and we operated approximately 81% of our net acreage. As of September 30, 2014, our total estimated proved reserves were approximately 21,756 MBoe (approximately 78% oil, 6% NGLs and 16% natural gas), of which approximately 38% were classified as PDP reserves and approximately 2% were classified as PDNP.
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How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
• | production volumes; |
• | realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on our oil production; |
• | lease operating expenses; and |
• | Adjusted EBITDAX. |
See “—Sources of Our Revenues,” “—Principal Components of Our Cost Structure” and “—Adjusted EBITDAX” for a discussion of these metrics.
Sources of Our Revenues
Our revenues are derived from the sale of our oil and liquids-rich natural gas production. Our oil and natural gas revenues do not include the effects of derivatives. For the six months ended June 30, 2014 and the years ended December 31, 2013 and 2012, our revenues were derived 90%, 93% and 93%, respectively, from oil sales and 10%, 7% and 7%, respectively, from natural gas and NGL sales.
Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Production Volumes
The following table presents historical production volumes for our predecessor’s properties for the six months ended June 30, 2014 and 2013 and the years ended December 31, 2013 and 2012 and our production volumes on a pro forma basis, after giving effect to the Dispositions, for the six months ended June 30, 2014 and the year ended December 31, 2013:
Predecessor | Pro Forma | |||||||||||||||||||
Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||
Oil (MBbls) | 619 | 253 | 713 | 651 | ||||||||||||||||
Natural gas and NGLs (MMcfe) | 985 | 380 | 933 | 852 | ||||||||||||||||
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Total (MBoe)(1) | 783 | 316 | 869 | 793 | ||||||||||||||||
Average net daily production (Boe/d) | 4,326 | 1,746 | 2,381 | 2,167 |
(1) | One Boe is equal to six Mcf of natural gas or one Bbl of oil based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
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 increased drilling as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risk Factors—Risks Related to Our Business” for a discussion of these and other risks affecting our proved reserves and production.
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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, thus lowering prices for Midland WTI. These lower prices adversely affected the prices we realized on oil sales and increased our differential to NYMEX WTI. However, several pipeline projects have recently been implemented and several more are underway, which we expect will ease these transportation difficulties and reduce our differentials to NYMEX to historical norms.
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, liquids-rich 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.
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.
Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||
Oil (per Bbl): | ||||||||||||||||
NYMEX WTI High | $ | 107.26 | $ | 98.44 | $ | 110.53 | $ | 109.77 | ||||||||
NYMEX WTI Low | 91.66 | 86.68 | 86.68 | 77.69 | ||||||||||||
Average NYMEX WTI | 100.82 | 94.29 | 98.02 | 94.17 | ||||||||||||
Differential to Average NYMEX WTI | (9.87 | ) | (8.08 | ) | (5.65 | ) | (7.83 | ) | ||||||||
Natural Gas (per Mcf)(1): | ||||||||||||||||
NYMEX Henry Hub High | $ | 6.15 | $ | 4.41 | $ | 4.46 | $ | 3.90 | ||||||||
NYMEX Henry Hub Low | 4.01 | 3.11 | 3.11 | 1.91 | ||||||||||||
Average NYMEX Henry Hub | 4.65 | 3.75 | 3.73 | 2.83 | ||||||||||||
Differential to Average NYMEX Henry Hub | 1.73 | 1.00 | 1.53 | 1.92 |
(1) | Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub has been positive. |
In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. Due to the inherent volatility in oil prices, we have historically used commodity derivative instruments, such as collars and swaps, to hedge price risk associated with a significant portion of our anticipated oil production. We have not historically hedged our natural gas production, as it generally represents a small overall percentage of our total revenue. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in 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.
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We expect to continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.
Our open positions as of June 30, 2014 were as follows:
Description & Production Period | Volume (Bbls) | Weighted Average Floor Price ($/ Bbl)(1) | Weighted Average Ceiling Price ($/ Bbl)(1) | Weighted Average Swap Price ($/ Bbl)(1) | ||||||||||||
Crude Oil Swaps: | ||||||||||||||||
July 2014 – December 2014 | 30,000 | — | — | $ | 90.42 | |||||||||||
July 2014 – December 2014 | 72,000 | — | — | 97.50 | ||||||||||||
July 2014 – December 2014 | 90,700 | — | — | 95.25 | ||||||||||||
July 2014 – December 2014 | 234,000 | — | — | 102.75 | ||||||||||||
January 2015 – December 2015 | 48,000 | — | — | 89.00 | ||||||||||||
January 2015 – December 2015 | 72,000 | — | — | 89.50 | ||||||||||||
January 2015 – December 2015 | 182,500 | — | — | 88.00 | ||||||||||||
January 2015 – December 2015 | 432,000 | — | — | 95.82 | ||||||||||||
January 2016 – June 2016 | 180,000 | — | — | 90.95 | ||||||||||||
Crude Oil Collars: | ||||||||||||||||
July 2014 – December 2014 | 12,000 | $ | 85.00 | $ | 94.50 | — | ||||||||||
July 2014 – December 2014 | 18,000 | 85.00 | 99.25 | — | ||||||||||||
July 2014 – December 2014 | 55,200 | 90.00 | 107.85 | — |
(1) | The oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. |
Principal Components of Our Cost Structure
Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, materials and supplies comprise the most significant portion of our LOE. 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 LOE 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.
We monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE 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 benchmark against other producers. Although we strive to reduce our LOE, 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 LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.
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Severance 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, natural gas and NGLs 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, which also trend with oil and gas prices.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our development and acquisition 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. Please read “—Critical Accounting Policies and Estimates—Impairment” for further discussion.
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, audit and other fees for professional services and legal compliance.
Derivative Gain (Loss). Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. We have not elected to apply cash flow hedge accounting, and consequently, recognize gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Fair value gains or losses, as well as cash receipts or payments on settled derivative contracts, are recognized in our results of operations. Cash flows from derivatives are reported as cash flows from operating activities.
Interest Expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility and with a term loan. 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 term loan in interest expense.
Adjusted EBITDAX
We define Adjusted EBITDAX as net income (loss) attributable to our predecessor before interest expense, income taxes, depreciation, depletion, amortization and accretion of asset retirement obligations, exploration and abandonment expenses, prepayment premium on extinguishment of debt, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation and (gains) losses from the sale of oil and natural gas properties.
Management believes Adjusted EBITDAX is useful because it allows us 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 EBITDAX 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 EBITDAX 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 EBITDAX are significant components in understanding and
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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 EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or in line with debt covenant definitions. For further discussion, please read “Prospectus Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measure.”
Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor
Our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below.
Incentive Unit Compensation
Certain of our employees hold incentive units in Centennial HoldCo that are intended to be compensation for services rendered to us. After members that have made capital contributions to Centennial HoldCo have received cumulative distributions in respect of their membership interests equal to specified rates of return, these incentive units may upon vesting entitle the holders to a disproportionate share of Centennial HoldCo’s distributions. These rates of return and the vesting schedule are described under “Executive Compensation— Narrative Disclosures—Incentive Units.” These incentive units are being accounted for as liability-classified awards with performance conditions under the Financial Accounting Board’s Accounting Standard Codification Topic 718–Stock Compensation (“ASC 718”).
At such time that the occurrence of the performance conditions associated with any of these incentive units are deemed probable, we will record non-cash compensation expense equal to a percentage of the then-determined fair value of those awards based on the implied service period that has been rendered at that date. As long as we continue to view the achievement of the performance conditions as probable of occurring, we will remeasure the amount of compensation expense to be recognized each period until the awards are settled. We expect that upon successful completion of the initial public offering at the midpoint of the price range set forth on the cover of this prospectus, the performance conditions associated with the Tier incentive units will be deemed probable of reaching payout, which will result in the recognition of non-cash compensation expense of approximately $ million. Assuming continued valuation of the Tier incentive units at the midpoint of the price range set forth on the cover of this prospects, we will have a remaining unrecognized non-cash compensation expense of approximately $ million, with respect to the Tier incentive units, which will be amortized over the remaining service period and result in a $ million non-cash compensation expense in the remainder of 2015 and $ million in 2016. Any change in fair value of the awards at each subsequent reporting period based on the required remeasurement will impact the aforementioned unrecognized compensation. Using the midpoint of the price range set forth on the cover of this prospectus, had the Tier incentive units been deemed probable of occurring, the associated unrecognized compensation would have been $ million. Please read “Executive Compensation—Narrative Disclosures—Incentive Units” for more information on the incentive units.
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 stockholders, 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.
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Income Taxes
Our predecessor reflects the consolidated and combined results of Centennial OpCo and Celero, both of which are treated as flow-through entities for federal income tax purposes and, as such, are not subject to federal income tax. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, the financial data attributable to our predecessor contains no provision for federal income tax. Centennial OpCo and Celero are subject to State of Texas franchise tax at less than 1% of modified pre-tax earnings. Centennial Resource Development, Inc. is taxed as a C-corp under the Code and subject to federal and state income taxes at a blended statutory rate of % of pretax earnings.
Increased Drilling Activity
Our board of directors has approved a capital budget for drilling, completion and recompletion activities and facilities costs of $ million for 2015. We plan to drill an estimated gross ( net) horizontal wells and gross ( net) vertical wells during 2015. Our 2015 capital budget represents a % increase over our $335 million 2014 capital budget. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.
Dispositions
Our predecessor made several dispositions in 2014, 2013 and 2012 as follows:
• | CO2Project Disposition—In May 2014, our predecessor conveyed certain oil and gas properties in Chaves County, New Mexico pursuant to which it had pursued a tertiary recovery project utilizing CO2 to increase production on such properties, including wells that produced 378 net Boe/d in the first half of 2014, for net cash proceeds of approximately $59.3 million. |
• | Wolfbone Disposition—In October 2013, our predecessor conveyed approximately 1,000 net acres in the Delaware Basin, including 187 non-operated wells that produced approximately 200 net Boe/d in the first half of 2013, for net cash proceeds of approximately $28.7 million. |
• | Resolute Disposition—In December 2012, our predecessor sold its (i) non-operated working interests in approximately 1,300 net acres in Howard County, Texas, including 23 producing wells that produced 377 net Boe/d in the third quarter of 2012, (ii) 2,767 net acres in Lea County, New Mexico, including 39 producing wells that produced 833 net Boe/d in the third quarter of 2012 and (iii) 2,455 additional net acres in the Permian Basin, including wells that produced approximately 208 net Boe/d in the third quarter of 2012, for net cash proceeds of approximately $111.9 million. |
Predecessor Results of Operations
Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Oil and Natural Gas and NGL 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:
Six Months Ended June 30, | Change | % Change | ||||||||||||||
2014 | 2013 | |||||||||||||||
(Unaudited) | ||||||||||||||||
Revenues (in thousands, except percentages): | ||||||||||||||||
Oil sales | $ | 56,295 | $ | 21,810 | $ | 34,485 | 158 | % | ||||||||
Natural gas and NGL sales | 6,283 | 1,805 | 4,478 | 248 | % | |||||||||||
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Total revenues | $ | 62,578 | $ | 23,615 | $ | 38,963 | 165 | % | ||||||||
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Six Months Ended June 30, | Change | % Change | ||||||||||||||
2014 | 2013 | |||||||||||||||
(Unaudited) | ||||||||||||||||
Average sales prices: | ||||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 90.95 | $ | 86.21 | $ | 4.74 | 5 | % | ||||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 88.56 | 64.20 | 24.36 | 38 | % | |||||||||||
Natural gas and NGLs (per Mcfe) | 6.38 | 4.75 | 1.63 | 34 | % | |||||||||||
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Total (per Boe) (excluding impact of cash settled derivatives)(1) | $ | 79.92 | $ | 74.73 | $ | 5.19 | 7 | % | ||||||||
Total (per Boe) (after impact of cash settled derivatives)(1) | $ | 78.03 | $ | 57.11 | $ | 20.92 | 37 | % | ||||||||
Production: | ||||||||||||||||
Oil (MBbls) | 619 | 253 | 366 | 145 | % | |||||||||||
Natural gas and NGLs (MMcfe) | 985 | 380 | 605 | 159 | % | |||||||||||
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Total (MBoe)(1) | 783 | 316 | 467 | 148 | % | |||||||||||
Average daily production volume: | ||||||||||||||||
Oil (Bbls/d) | 3,420 | 1,398 | 2,022 | 145 | % | |||||||||||
Natural gas and NGLs (Mcfe/d) | 5,442 | 2,099 | 3,343 | 159 | % | |||||||||||
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Total (Boe/d)(1) | 4,326 | 1,746 | 2,580 | 148 | % |
(1) | One Boe is equal to six Mcf of natural gas or one Bbl of oil based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
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.
Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
Average realized oil price ($/Bbl) | $ | 90.95 | $ | 86.21 | ||||
Average NYMEX ($/Bbl) | 100.82 | 94.29 | ||||||
Differential to NYMEX | (9.87 | ) | (8.08 | ) | ||||
Average realized oil price to NYMEX percentage | 90 | % | 91 | % | ||||
Average realized natural gas price ($/Mcf)(1) | $ | 6.38 | $ | 4.75 | ||||
Average NYMEX ($/Mcf) | 4.65 | 3.75 | ||||||
Differential to NYMEX | 1.73 | 1.00 | ||||||
Average realized natural gas price to NYMEX percentage | 137 | % | 127 | % |
(1) | Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub has been positive. |
Oil sales increased 158%, or $34.5 million, to $56.3 million for the six months ended June 30, 2014 from $21.8 million for the six months ended June 30, 2013 as a result of an increase in oil production of 145%, or 366 MBbls, and a 5%, or $4.74 per Bbl, increase in the average realized oil price. The increase in production is
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primarily due to an increase in horizontal drilling activity on our retained Delaware properties (“our retained properties”), which resulted in an increase in production of 296%, or 414 MBbls, to 554 MBbls in the first half of 2014 from 140 MBbls in the first half of 2013. Since the first half of 2013, we have drilled 20 gross (17 net) additional horizontal wells, bringing our total horizontal well count to 27 gross (22 net) as of June 30, 2014. The increase in production volumes was primarily offset by the Wolfbone Disposition and the CO2 Project Disposition. Oil production from these two properties was 65 MBbls in the first half of 2014 and 114 MBbls in the first half of 2013.
Natural gas and NGL sales increased 248%, or $4.5 million, to $6.3 million for the six months ended June 30, 2014 from $1.8 million for the six months ended June 30, 2013 as a result of an increase in natural gas and NGL production volumes of 159%, or 605 MMcfe, and a 34%, or $1.63 per Mcfe, increase in our average realized natural gas price. The increase in natural gas and NGL production was primarily due to an increase in horizontal drilling activity on our retained properties, which resulted in an increase in natural gas and NGL production of 216%, or 658 MMcfe, to 962 MMcfe in the first half of 2014 from 304 MMcf in the first half of 2013. The production increases were partially offset by the Wolfbone Disposition and the CO2 Project Disposition. Natural gas and NGL production from these two properties was 23 MMcfe in the first half of 2014 and 76 MMcfe in the first half of 2013.
Six Months Ended June 30, | Change | % Change | ||||||||||||||
2014 | 2013 | |||||||||||||||
(Unaudited) | ||||||||||||||||
Operating expenses (in thousands, except percentages): | ||||||||||||||||
Lease operating expenses | $ | 8,156 | $ | 8,489 | $ | (333 | ) | (4 | )% | |||||||
Severance and ad valorem taxes | 3,312 | 1,476 | 1,836 | 124 | % | |||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,146 | 10,624 | 18,522 | 174 | % | |||||||||||
Exploration and abandonment expenses | 2 | 98 | (96 | ) | (98 | )% | ||||||||||
General and administrative expenses | 22,683 | 6,830 | 15,853 | 232 | % | |||||||||||
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Total operating expenses before loss (gain) on sale of oil and natural gas properties | $ | 63,299 | $ | 27,517 | $ | 35,782 | 130 | % | ||||||||
Loss (gain) on sale of oil and natural gas properties | 2,390 | (1,049 | ) | 3,439 | NM | (1) | ||||||||||
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Total operating expenses after loss (gain) on sale of oil and natural gas properties | $ | 65,689 | $ | 26,468 | $ | 39,221 | 148 | % | ||||||||
Expenses per Boe: | ||||||||||||||||
Lease operating expenses | $ | 10.42 | $ | 26.86 | $ | (16.44 | ) | (61 | )% | |||||||
Severance and ad valorem taxes | 4.23 | 4.67 | (0.44 | ) | (9 | )% | ||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 37.22 | 33.62 | 3.60 | 11 | % | |||||||||||
Exploration and abandonment expenses | 0.00 | 0.31 | (0.31 | ) | (100 | %) | ||||||||||
General and administrative expenses | 28.97 | 21.61 | 7.36 | 34 | % | |||||||||||
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Total operating expenses per Boe | $ | 80.84 | $ | 87.07 | $ | (6.23 | ) | (7 | )% | |||||||
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(1) | Fluctuation in terms of percentage change is not meaningful. |
Lease Operating Expenses. LOE decreased 4% to $8.2 million for the six months ended June 30, 2014 from $8.5 million for the six months ended June 30, 2013. The decrease is primarily due to LOE attributable to the Wolfbone Disposition and the CO2 Project Disposition, which resulted in a decrease of $1.7 million in the first half of 2014 compared to the first half of 2013. The decrease was partially offset by an increase in LOE of
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$1.4 million attributable to our retained properties primarily due to an increase in production in the first half of2014 compared to the first half of 2013. LOE, excluding our dispositions, was $5.48 per Boe in the first half of 2014 compared to $13.71 per Boe in the first half of 2013. The decrease per Boe is primarily due to the aforementioned increase in our production on our retained properties.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased 124%, or $1.8 million, to $3.3 million for the six months ended June 30, 2014 from $1.5 million for the six months ended June 30, 2013, primarily as a result of an increase in wellhead revenues. Severance and ad valorem taxes per Boe, excluding our dispositions, was $3.94 per Boe for the six months ended June 30, 2014 compared to $3.95 per Boe for the six months ended June 30, 2013.
Depreciation, Depletion and Amortization. DD&A expense increased 174%, or $18.5 million, to $29.1 million for the six months ended June 30, 2014 from $10.6 million for the six months ended June 30, 2013 primarily due to an increase in production volumes. DD&A, excluding our dispositions, was $27.7 million, or $38.74 per Boe, in the first half of 2014 compared to $6.1 million or $32.67 per BOE in the first half of 2013. DD&A expense, excluding our dispositions, increased due to the aforementioned increase in production on our retained properties. DD&A per Boe primarily increased as we shifted toward drilling more horizontal wells, which are comparatively more expensive than vertical wells.
General and Administrative Expenses. General and administrative (“G&A”) expenses increased 232%, or $15.9 million, to $22.7 million for the six months ended June 30, 2014 from $6.8 million for the six months ended June 30, 2013. The increase is primarily due to $12.4 million of incentive compensation recorded due to the achievement of certain performance criteria associated with our predecessor’s incentive units. Also included in the increase are severance payments of $2.2 million to terminated employees of our predecessor.
Loss (gain) on Sale of Assets. For the six months ended June 30, 2014, the loss on sale of assets is primarily due to the CO2 Project Disposition, which resulted in a realized loss on sale of $2.2 million. For the six months ended June 30, 2013, we recognized an additional gain of $1.5 million related to the Resolute Disposition as result of title defects and other contingent post-closing items accrued as of December 31, 2012. The gain on the Resolute Disposition is offset by other small dispositions in the first half of 2013.
Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:
Six Months Ended June 30, 2014 | $ Change | % Change | ||||||||||||||
2014 | 2013 | |||||||||||||||
(Unaudited) | ||||||||||||||||
Other (expense) income (in thousands, except percentages): | ||||||||||||||||
Interest expense | $ | (599 | ) | $ | (153 | ) | $ | (446 | ) | 292 | % | |||||
Loss on derivative instruments | (6,164 | ) | (1,184 | ) | (4,980 | ) | 421 | % | ||||||||
Other income (expense) | 239 | (183 | ) | 422 | NM | (1) | ||||||||||
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Total other expense | $ | (6,524 | ) | $ | (1,520 | ) | $ | (5,004 | ) | 329 | % | |||||
Income tax expense | $ | (1,027 | ) | $ | (447 | ) | $ | (580 | ) | 130 | % |
(1) | Fluctuation in terms of percentage change is not meaningful. |
Interest Expense. Interest expense increased 292%, or $0.4 million, to approximately $0.6 million for the six months ended June 30, 2014 from $0.2 million for the six months ended June 30, 2013 due to an increase in the borrowings under our revolving credit facility during the first half of 2014 compared to the first half of 2013.
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Loss on Derivative Instruments. During the six months ended June 30, 2014, we recognized a $6.2 million derivative fair value loss as compared to a $1.2 million loss in the six months ended June 30, 2013, primarily as a result of the impact of changing commodity prices on increased hedging activity.
Income Tax Expense.During the six months ended June 30, 2014, we recognized $1.0 million of expense associated with our Texas margin tax obligation, an increase of $0.6 million, or 130%, as compared to the $0.4 million we recognized during the six months ended June 30, 2013. The increase is due to an increase in our estimated income subject to Texas gross margin tax year-over-year.
Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
Oil and Natural Gas Revenues. The following table provides the components of our revenues for the years indicated, as well as each year’s respective average prices and production volumes:
Year Ended December 31, | Change | % Change | ||||||||||||||
2013 | 2012 | |||||||||||||||
Revenues (in thousands, except percentages): | ||||||||||||||||
Oil sales | $ | 65,863 | $ | 56,207 | $ | 9,656 | 17 | % | ||||||||
Natural gas and NGL sales | 4,907 | 4,051 | 856 | 21 | % | |||||||||||
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Total revenues | $ | 70,770 | $ | 60,258 | $ | 10,512 | 17 | % | ||||||||
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Average sales prices: | ||||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 92.37 | $ | 86.34 | $ | 6.03 | 7 | % | ||||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 74.63 | 67.18 | 7.45 | 11 | % | |||||||||||
Natural gas and NGLs (per Mcfe) | 5.26 | 4.75 | 0.51 | 11 | % | |||||||||||
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Total (per Boe) (excluding impact of cash settled derivatives)(1) | $ | 81.44 | $ | 75.99 | $ | 5.45 | 7 | % | ||||||||
Total (per Boe) (after impact of cash settled derivatives)(1) | $ | 66.88 | $ | 60.26 | $ | 6.62 | 11 | % | ||||||||
Production: | ||||||||||||||||
Oil (MBbls) | 713 | 651 | 62 | 10 | % | |||||||||||
Natural gas and NGLs (MMcfe) | 933 | 852 | 81 | 10 | % | |||||||||||
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Total (MBoe)(1) | 869 | 793 | 76 | 10 | % | |||||||||||
Average daily production volumes: | ||||||||||||||||
Oil (Bbls/d) | 1,953 | 1,779 | 174 | 10 | % | |||||||||||
Natural gas and NGLs (Mcfe/d) | 2,556 | 2,328 | 228 | 10 | % | |||||||||||
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Total (Boe/d)(1) | 2,381 | 2,167 | 214 | 10 | % |
(1) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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, | ||||||||
2013 | 2012 | |||||||
Average realized oil price ($/Bbl) | $ | 92.37 | $ | 86.34 | ||||
Average NYMEX ($/Bbl) | 98.02 | 94.17 | ||||||
Differential to NYMEX | (5.65 | ) | (7.83 | ) | ||||
Average realized oil price to NYMEX percentage | 94 | % | 92 | % | ||||
Average realized natural gas price ($/Mcf)(1) | $ | 5.26 | $ | 4.75 | ||||
Average NYMEX ($/Mcf) | 3.73 | 2.83 | ||||||
Differential to NYMEX | 1.53 | 1.92 | ||||||
Average realized natural gas price to NYMEX percentage | 141 | % | 168 | % |
(1) | Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub has been positive. |
Oil sales increased 17% to $65.9 million in 2013 from $56.2 million in 2012 as result of an increase in oil production volumes of 10% or 62 MBbls and a 7% or $6.03 per Bbl increase in our average realized oil price. Our increase in oil production is primarily a result of an increase in drilling activity on our retained properties, which resulted in an increase in production of 441%, or 397 MBbls, to 487 MBbls in 2013 from 90 MBbls in 2012 and an increase in production of 77 MBbls attributable to our CO2 properties. The increase in production was primarily offset by a decrease of 412 MBbls attributable to the Resolute Disposition and the Wolfbone Disposition.
Natural gas and NGL sales increased 21% to $4.9 million in 2013 from $4.1 million in 2012 as a result of an increase in natural gas and NGL production volumes of 10%, or 81 MMcf, and a 11%, or $0.51 per Mcf, increase in our average realized natural gas price. Our increase in natural gas and NGL production was primarily a result an increase in drilling activity on our retained properties, which resulted in an increase in production of 333% to 801 MMcf in 2013 from 185 MMcfe in 2012. The decrease in production was primarily offset by a decrease of 525 MMcf attributable to the Resolute Disposition and the Wolfbone Disposition.
Operating Expenses. The following table summarizes our expenses for the periods indicated:
Year Ended December 31, | $ Change | % Change | ||||||||||||||
2013 | 2012 | |||||||||||||||
Operating expenses (in thousands, except percentages): | ||||||||||||||||
Lease operating expenses | $ | 19,193 | $ | 22,580 | $ | (3,387 | ) | (15 | )% | |||||||
Severance and ad valorem taxes | 4,153 | 4,275 | (122 | ) | (3 | )% | ||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,285 | 21,035 | 8,250 | 39 | % | |||||||||||
Exploration and abandonment expenses | 8,561 | 10,381 | (1,820 | ) | (18 | )% | ||||||||||
General and administrative expenses | 16,842 | 6,939 | 9,903 | 143 | % | |||||||||||
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Total operating expenses | $ | 78,034 | $ | 65,210 | $ | 12,824 | 20 | % | ||||||||
Gain on sale of oil and natural gas properties | (16,756 | ) | (36,407 | ) | 19,651 | NM | (1) | |||||||||
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Total operating expenses after gain on sale of oil and natural gas properties | $ | 61,278 | $ | 28,803 | $ | 32,475 | 113 | % |
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Year Ended December 31, | $ Change | % Change | ||||||||||||||
2013 | 2012 | |||||||||||||||
Average unit costs per Boe: | ||||||||||||||||
Lease operating expenses | $ | 22.09 | $ | 28.47 | $ | (6.38 | ) | (22 | )% | |||||||
Severance and ad valorem taxes | 4.78 | 5.39 | (0.61 | ) | (11 | )% | ||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 33.70 | 26.53 | 7.17 | 27 | % | |||||||||||
Exploration and abandonment expenses | 9.85 | 13.09 | (3.24 | ) | (25 | )% | ||||||||||
General and administrative expenses | 19.38 | 8.75 | 10.63 | 121 | % | |||||||||||
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Total operating expenses per Boe | $ | 89.80 | $ | 82.23 | $ | 7.57 | 9 | % | ||||||||
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(1) | Fluctuation in terms of percentage change is not meaningful. |
Lease Operating Expenses. LOE decreased 15%, or $3.4 million, to $19.2 million in 2013 from $22.6 million in 2012. The decrease was due to the Resolute Disposition, which accounted for $14.1 million of our LOE in 2012. This decrease was offset by an increase in LOE of 188%, or $3.8 million, attributable to our retained properties, due to an increase in production year-over-year of 413%, or 500 MBoe. Additionally, LOE primarily associated with our CO2 properties increased 92%, or $5.6 million, from 2012. LOE per Boe, excluding our dispositions, was $9.35 for the year ended December 31, 2013 compared to $16.65 for the year ended December 31, 2012. The decrease per Boe is primarily due to the aforementioned increase in production on our retained properties.
Severance and Ad Valorem Taxes. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. The decrease in total production taxes in 2013 as compared to 2012 is primarily due to the Resolute Disposition, which accounted for $2.8 million or 65% of production taxes in 2012. The decrease was offset by an increase in production taxes directly attributable to an increase in drilling activity on our retained properties, which resulted in a production increase year-over-year of 413%, or 500 MBoe, and an increase in the average realized price in 2013 compared to 2012. Additionally, production taxes attributable to our CO2 properties increased $0.6 million primarily to an increase in production.
Depreciation, Depletion and Amortization. DD&A expense increased 39%, or $8.3 million, to $29.3 million in 2013 from $21.0 million in 2012 primarily due to an increase in production. DD&A, excluding our dispositions, was $21.7 million, or $34.93 per Boe, in 2013 compared to $4.1 million, or $33.55 per Boe, in 2012. DD&A expense, excluding our dispositions, increased due to the aforementioned increase in production on our retained properties. DD&A per Boe primarily increased as we shifted toward drilling more horizontal wells, which are comparatively more expensive than vertical wells.
General and Administrative Expenses. G&A expenses increased 143% to $16.8 million in 2013 from $6.9 million in 2012. The increase in G&A is the result of having two distinct management teams and employees associated with each of our predecessors along with our growing capital program and oil production levels primarily associated with our retained properties.
Gain on Sale of Oil and Natural Gas Properties.We recorded a gain on sale of assets of $16.8 million in 2013 and $36.4 million in 2012. These gains were primarily attributable to the following:
• | In October 2013, we completed the Wolfbone Disposition for total proceeds of approximately $28.7 million and realized a gain of $7.7 million. |
• | In August 2013, we sold oil and natural gas properties in the Midland Basin for total proceeds of $17.1 million and realized a $7.9 million gain on sale. |
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• | In January 2013, we recognized an additional gain of $1.5 million related to the Resolute Disposition as a result of title defects and other contingent post-closing items accrued as of December 31, 2012. |
• | In 2012, we completed the Resolute Disposition for net cash proceeds of approximately $111.9 million and realized a $36.4 million gain on sale. |
Other Income and Expenses. The following table summarizes our other income and expenses for the years indicated:
Year Ended December 31, | $ Change | % Change | ||||||||||||||
2013 | 2012 | |||||||||||||||
Other income (expense) (in thousands, except percentages): | ||||||||||||||||
Interest expense | $ | (513 | ) | $ | (1,084 | ) | $ | 571 | (53 | )% | ||||||
(Loss) gain on derivative instruments | (4,410 | ) | 2,868 | (7,278 | ) | NM | (1) | |||||||||
Other income (expense) | 122 | (394 | ) | 516 | NM | (1) | ||||||||||
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Total other income (expense) | $ | (4,801 | ) | $ | 1,390 | $ | (6,191 | ) | NM | (1) | ||||||
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Income tax expense | $ | (1,079 | ) | $ | (563 | ) | $ | (516 | ) | 92 | % |
(1) | Fluctuation in terms of percentage change is not meaningful. |
Interest Expense. Interest expense decreased $0.6 million, or 53%, to $0.5 million in 2013 from approximately $1.1 million in 2012 as a result of a decrease in the amount outstanding under our revolving credit facility during 2013 as compared to 2012.
(Loss) gain on Derivative Instruments. During 2013, we recognized a $4.4 million loss on derivative instruments compared to a $2.9 million gain on derivative instruments in 2012, primarily as a result of the impact of changing commodity prices on increased hedging activities.
Income Tax Expense.During the year ended December 31, 2013, we recognized $1.1 million of expense associated with our Texas margin tax obligation, an increase of $0.5 million, or 92%, as compared to the $0.6 million we recognized during the year ended December 31, 2012. The increase is due to an increase in our estimated income attributable to Texas gross margin tax year-over-year.
Capital Requirements and Sources of Liquidity
Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our predecessor’s primary sources of liquidity have been capital contributions from their equity sponsor, borrowings under our predecessor’s revolving credit facility and term loan, proceeds from asset dispositions and cash flows from operations. To date, our predecessor’s primary use of capital has been for the development and acquisition of oil and natural gas properties.
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 expect to maintain an active hedging program that seeks to reduce our exposure to lower commodity prices and protect our cash flow.
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 revolving credit facility, 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 agreement. 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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Our 2014 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $335 million, excluding leasing and other acquisitions. Substantially, all of our capital budget will be spent in the Delaware Basin. As of June 30, 2014, we had incurred capital costs of approximately $160 million.
We currently estimate that our 2015 capital budget for drilling, completion, recompletion activities and facilities costs will be approximately $ million. We expect that approximately % of our 2015 drilling and completion budget, or $ million, will be devoted to the drilling of horizontal wells. In 2015, we expect to allocate approximately $ million of our capital budget for the drilling and completion of operated wells and $ million for our participation in the drilling and completion of non-operated wells.
Because we are the operator of a high percentage of our net acreage, the amount and timing of these capital expenditures are largely discretionary and within our control. We could choose to defer a portion of our 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 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—Oil and Natural Gas Production Prices and Costs—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.
We intend to use a portion of the net proceeds from this offering to fully repay outstanding borrowings under our revolving credit facility. Our borrowing base under our revolving credit facility was $80 million as of June 30, 2014. In August 2014, as part of the semi-annual redetermination process, our borrowing base was increased to $115 million. Also, in connection with the Combination, our borrowing base was further increased to $145 million in October 2014, and we entered into a $65 million senior secured term loan.
Based upon current oil and natural gas price expectations for 2015, following the closing of this offering, we believe that our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current capital program. 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. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. 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 program, 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 maintain our production or replace our reserves.
Working Capital
Our working capital, which we define as current assets minus current liabilities, totaled $0.4 million, $20.1 million and $54.7 million at June 30, 2014, December 31, 2013 and December 31, 2012, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled $55.0 million, $42.2 million and
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$46.5 million at June 30, 2014, December 31, 2013 and December 31, 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 revolving credit facility 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.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||
(Unaudited) | ||||||||||||||||
(In thousands) | ||||||||||||||||
Net cash provided by operating activities | $ | 53,943 | $ | 2,811 | $ | 13,416 | $ | 20,359 | ||||||||
Net cash used in investing activities | $ | (28,602 | ) | $ | (63,005 | ) | $ | (136,517 | ) | $ | (46,395 | ) | ||||
Net cash (used in) provided by financing activities | $ | (12,502 | ) | $ | 44,043 | $ | 118,742 | $ | 72,523 |
Net cash provided by operating activities was approximately $53.9 million and $2.8 million for the six months ended June 30, 2014 and 2013, respectively. Revenues increased $39.0 million for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013, primarily as a result of increased production, and therefore our net cash provided by operating activities increased 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.
Net cash provided by operating activities was approximately $13.4 million and $20.4 million for the years ended December 31, 2013 and 2012. Revenues increased $10.5 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012, primarily as a result of increased production, and therefore our net cash provided by operating activities increased 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.
Net cash used in investing activities was approximately $28.6 million and $63.0 million for the six months ended June 30, 2014 and 2013, respectively. The decrease in the amount of cash used in investing activities in the six months ended June 30, 2014 compared to the six months ended June 30, 2013 is primarily due to the CO2Project Disposition and disposition of our midstream assets, which offset $140.9 million of expenditures attributable to the development of our oil and natural gas properties and $9.4 million of acquisition expenditures for the six months ended June 30, 2014.
Net cash used in investing activities was approximately $136.5 million and $46.4 million for the years ended December 31, 2013 and 2012, respectively. The increased amount of cash used in investing activities in the year ended December 31, 2013 was primarily due to an increase of $63.9 million attributable to the development of our oil and natural gas properties. In 2013, we had proceeds from sales of oil and natural gas properties of $46.3 million compared to $112.3 million in 2012.
Net cash used in financing activities was approximately $12.5 million for the six months ended June 30, 2014 compared to net cash provided by financing activities of $44.0 million for the six months ended June 30, 2013. For the six months ended June 30, 2014, net cash used in financing activities included borrowings of long-term debt of $94.0 million offset by long-term debt repayments of $48.0 million and capital contributions of $28.7 million offset by the repurchase of equity interests of $87.1 million. For the six months ended June 30, 2013, net cash provided by financing activities included $65.2 million of capital contributions offset by $21.1 million of capital distributions.
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Net cash provided by financing activities was approximately $118.7 million and $72.5 million for the years ended December 31, 2013 and 2012, respectively. For 2013, net cash provided by financing activities included borrowings of long-term debt of $57.0 million offset by long-term debt repayments of $28.0 million and capital contributions of $114.9 million primarily offset by capital distributions of $21.1 million. For 2012, net cash provided by financing activities included repayments of long-term debt of $60.5 million offset by borrowings of long-term debt of $50.5 million and capital contributions of $102.3 million offset by the repurchase of equity interests of $19.6 million.
Our Revolving Credit Facility and Our Term Loan
On June 11, 2013, Centennial OpCo entered into a revolving credit agreement (the “old revolving credit facility”) with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, with a maximum credit amount of $500 million (subject to the borrowing base) and a sublimit for letters of credit of $15 million. As of June 30, 2014, Centennial OpCo had $75 million of borrowings and $50,000 of letters of credit outstanding under the old revolving credit facility, and the borrowing base was $80 million. In August 2014, as part of the semi-annual redetermination process, the borrowing base was increased to $115 million. Centennial OpCo was in compliance in all material respects with all covenants and ratios set forth in the old revolving credit facility as of June 30, 2014, except with respect to the minimum current ratio, which is the ratio of Centennial OpCo’s consolidated current assets (including unused commitments under the old revolving credit facility and excluding non-cash assets under ASC 815 and certain restricted cash) to Centennial OpCo’s consolidated current liabilities (excluding the current portion of long-term debt under the old revolving credit facility and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0, for which Centennial OpCo received a waiver. At June 30, 2014, the variable rate of interest under the old revolving credit facility was 2.53%. The old revolving credit facility had a maturity date of June 11, 2018.
On October 15, 2014, Centennial OpCo entered into an amended and restated credit agreement (our “credit agreement”) with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65 million (our “term loan”) and a revolving credit facility (our “revolving credit facility”) with commitments of $500 million (subject to the borrowing base), with a sublimit for letters of credit of $15 million. As of October 15, 2014, the borrowing base under our revolving credit facility was $145 million. As of November 1, 2014, we had $43 million outstanding under our revolving credit facility and $300,000 of letters of credit outstanding. We intend to use a portion of the net proceeds of this offering to fully repay outstanding borrowings under our revolving credit facility. Our term loan matures on April 15, 2017, and our revolving credit facility matures on October 15, 2019.
The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 (and in 2015, on January 1 and July 1, as well) by the lenders in their sole discretion. The credit agreement also allows, in 2016 and thereafter, for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of Centennial OpCo’s proved oil and natural gas reserves and estimated cash flows from these reserves and Centennial OpCo’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders.
Our term loan and borrowings under our revolving credit facility are secured by liens on (i) oil and gas properties constituting at least 80% of the total value of all of Centennial OpCo’s proved oil and gas properties and (ii) equity interests in all of Centennial OpCo’s restricted subsidiaries. Our term loan and borrowings under our revolving credit facility are guaranteed by all of Centennial OpCo’s subsidiaries other than any subsidiary that Centennial OpCo has designated as an unrestricted subsidiary.
Our credit agreement contains restrictive covenants that limit Centennial OpCo’s ability to, among other things:
• | incur additional indebtedness; |
• | make investments and loans; |
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• | enter into mergers; |
• | make or declare dividends; |
• | enter into commodity hedges exceeding a specified percentage or Centennial OpCo’s expected production; |
• | enter into interest rate hedges exceeding a specified percentage of Centennial OpCo’s outstanding indebtedness; |
• | incur liens; |
• | sell assets; and |
• | engage in transactions with affiliates. |
Our credit agreement also requires Centennial OpCo to maintain compliance with the following financial ratios:
• | a current ratio, which is the ratio of Centennial OpCo’s consolidated current assets (including unused commitments under our revolving credit facility and excluding non-cash assets under ASC 815 and certain restricted cash) to Centennial OpCo’s consolidated current liabilities (excluding the current portion of long-term debt under our credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and |
• | a leverage ratio, which is the ratio of Total Funded Debt (as defined in our credit agreement) to consolidated EBITDAX (as defined in our credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0 (with such ratio to be annualized for the first three fiscal quarters following October 15, 2014). |
Loans under our credit agreement may be base rate loans or LIBOR loans. Principal amounts borrowed are payable on the term loan maturity date and the revolving credit maturity date, as applicable, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of the borrowing base utilized. Centennial OpCo also pays a commitment fee on unused amounts of our revolving credit facility ranging from 37.5 basis points to 50 basis points, depending on the percentage of the borrowing base utilized. Centennial OpCo may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
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Contractual Obligations
A summary of our predecessor’s contractual obligations as of December 31, 2013 is provided in the following table.
Payments Due by Period For the Year Ended December 31, | ||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Revolving credit facility(1) | $ | — | $ | — | $ | — | $ | — | $ | 29,000 | $ | — | $ | 29,000 | ||||||||||||||
Drilling rig commitments(2) | 13,930 | — | — | — | — | — | 13,930 | |||||||||||||||||||||
Office and equipment leases | 1,775 | 163 | — | — | — | — | 1,938 | |||||||||||||||||||||
Asset retirement obligations(3) | — | — | — | — | — | 3,557 | 3,557 | |||||||||||||||||||||
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Total(4)(5) | $ | 15,705 | $ | 163 | $ | — | $ | — | $ | 29,000 | $ | 3,557 | $ | 48,425 | ||||||||||||||
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(1) | This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on Centennial OpCo’s 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. We intend to use a portion of the net proceeds from this offering to fully repay borrowings under our revolving credit facility. |
On October 15, 2014, Centennial OpCo entered into an amended and restated credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders pursuant to which the maturity date of our revolving credit facility was extended from June 2018 to October 2019 and pursuant to which we obtained a $65 million senior secured term loan that matures on April 15, 2017.
(2) | The values in the table represent the gross amounts that our predecessor is committed to pay. |
(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) | Not included in the table above is our CO2purchase contract. On January 14, 2014 we contracted to purchase 46.4 Bcf of CO2 from 2014 to 2022 at a price equal to 1.75% of the monthly NYMEX WTI price plus the then applicable Cortex Pipeline Tariff, which is currently $0.18 per Mcf. The contract can be terminated at any time by paying a termination fee equal to one-fourth of the remaining contracted volumes multiplied by the then current price. At December 31, 2013 the estimated termination fee for this contract was approximately $22.0 million. In May 2014, this contract was assigned to the purchaser in the CO2 Project Disposition. |
(5) | We may owe the seller of the CO2 properties an additional $1.7 million if and when the net production attributed to the properties sold in the CO2Project Disposition exceeds 1,000 Bbl/d, net to Celero, for 30 consecutive days. We sold these properties in the first half of 2014. |
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
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volatility is expected to continue in the future. Our realized prices are primarily driven by the prevailing prices for oil and the prevailing spot prices for natural gas. 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. Our predecessor has used, and we expect to continue to use, derivative contracts to reduce our exposure to the changes in the prices of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. Our credit agreement limits our ability to enter into commodity hedges covering greater than 80% of our reasonably anticipated projected production volume.
The fair value of our oil derivative contracts as of June 30, 2014 was a net liability of $5.2 million. For information regarding the terms of these hedges, see “—Overview—Realized Prices on the Sale of Oil, Natural Gas and NGLs” above.
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. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The counterparties to our predecessor’s derivative contracts currently in place have 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 our 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.
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 June 30, 2014, our predecessor had $75 million of debt outstanding, with an assumed weighted average interest rate of 2.53%. Interest is calculated under the terms of our credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $0.75 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated and combined financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated and combined financial statements.
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Successful Efforts Method of Accounting for Oil and Natural Gas Activities
We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Geological and geophysical costs are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in earnings.
Impairment
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows from our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.
Unproved properties costs consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.
Oil and Gas Reserves
Reserve estimates are inherently imprecise. Oil and gas properties are depleted by field using the units of production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased in the future. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Revenue Recognition
Oil and natural gas revenues are recognized when the product is sold to a purchaser, delivery has occurred, written evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonably assured. We follow the sales method of accounting for oil and natural gas revenue, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.
Derivative Financial Instruments
We use derivative contracts to hedge the effects of fluctuations in the prices of oil. We record such derivative instruments as assets or liabilities in the statements of financial position (see Note 6 – Derivative
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Instruments to our Consolidated and Combined Financial Statements for further information on fair value). Estimating the fair value of derivative financial instruments requires management to make estimates and judgments regarding volatility and counterparty credit risk.
We have not designated any of our derivative instruments as hedges for accounting purposes for any of the periods presented. The changes in fair value of the contracts are included in other income (expense) in the period of the change.
Acquisitions
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 may 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.
Asset Retirement Obligations
We recognize as a liability an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. We measure the fair value of the ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.
Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Recently Issued Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” (“ASU 2014-08”). ASU 2014-08 changed the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. Our predecessor elected to early adopt ASU 2014-08 on a prospective basis. The adoption of ASU 2014-08 did not have a material impact on the consolidated and combined financial statements at December 31, 2013 or 2012.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific
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guidance. An entity is required to apply ASU 2014-09 for annual and interim reporting periods beginning after December 15, 2016. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.
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. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 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 December 31, 2012 or 2013. 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 natural 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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The following discussion should be read in conjunction with the “Selected Historical and Pro Forma Consolidated and Combined Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus.
The estimated proved reserve information for our properties as of September 30, 2014 contained in this prospectus is based on a reserve report relating to our properties prepared by NSAI, our independent petroleum engineer.
Business Overview
We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our properties consist of large, contiguous acreage blocks primarily in Reeves, Ward and Pecos counties in West Texas.
As of September 30, 2014, our portfolio included 35 producing horizontal wells, which represented approximately % of our production. Our horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe our acreage is prospective for the 2nd Bone Spring and Avalon Shale zones, where other operators have experienced drilling success near our acreage.
We have leased or acquired approximately 40,500 net acres as of September 30, 2014, approximately 81% of which we operate. We currently operate four horizontal rigs, and we expect to add a fifth horizontal rig in the second quarter of 2015 and a sixth horizontal rig in the second half of 2015. Since January 2013, all of our wells drilled in the Delaware Basin have been horizontal wells. We plan to continue this horizontal drilling program with an ongoing focus on optimizing completions and reducing costs.
The Permian Basin is an attractive operating area due to its extensive original oil-in-place, favorable operating environment, multiple horizontal zones, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. According to the EIA, the Permian Basin is the most prolific oil producing area in the United States, accounting for 18% of total U.S. crude oil production in 2013. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin.
Horizontal drilling activity has historically been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. According to Baker Hughes, four of the top six Permian Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county with 50 rigs as of September 30, 2014. The number of horizontal rigs within the Permian Basin, and specifically Reeves County, has been subject to a significant upward trend over the past year. As shown in the chart below, Reeves County currently has the most horizontal rigs in the Permian Basin, and the rig count has grown approximately 213% in the last twelve months.
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We were formed by an affiliate of NGP, a family of energy-focused private equity investments funds. Our goal is to build the premier development and acquisition company focused on horizontal drilling in the Delaware Basin. Our key management and technical team members average approximately 26 years of experience and have successfully led development operations in prolific oil basins in the Continental United States, including horizontal development in the Permian, Bakken and Niobrara plays. This expertise and technical acumen have been applied to the horizontal drilling and multi-stage completions on our properties, resulting in drilling success and continuous operating improvements across multiple zones.
We have assembled a multi-year inventory of horizontal drilling projects. As of September 30, 2014, we had identified 1,232 gross horizontal drilling locations in the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C zones across our Delaware Basin acreage based on spacing of five to six wells per zone per 640 acre section. We believe that development drilling of these locations, as well as further downspacing, will allow us to grow our production and reserves. In addition, we believe we will improve well economics via drilling optimization, including reduction of spud-to-rig release days and increased use of pad drilling. Furthermore, we plan to pursue accretive acquisitions that are complementary to our strategic and financial objectives.
Our near term drilling program is focused on the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C zones. Based upon our and other operators’ well results and our analysis of geologic and engineering data, we believe the 2nd Bone Spring and Avalon Shale formations may also be prospective across our acreage, and we may integrate these zones into our future drilling program as they become further delineated. We believe our large acreage blocks allow us to optimize our horizontal development program to maximize our resource recovery and our returns. The following table provides a summary of our horizontal drilling locations by zone as of September 30, 2014.
Identified Horizontal Drilling Locations(1)(2) | ||||
Total | ||||
Zones: | ||||
3rd Bone Spring | 69 | |||
Upper Wolfcamp A | 414 | |||
Lower Wolfcamp A | 353 | |||
Wolfcamp B | 85 | |||
Wolfcamp C | 311 | |||
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Total Horizontal Locations(3)(4) | 1,232 | |||
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(1) | Our total identified horizontal drilling locations include 47 locations associated with proved undeveloped reserves as of September 30, 2014. We have estimated our drilling locations based on well spacing |
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assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our combined horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. See “—Our Properties.” The drilling locations that 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 ability to add additional proved reserves to our existing proved reserves. See “Risk Factors—Risks Related to Our Business—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.” Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See “Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled out 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.” |
(2) | Our horizontal drilling location count implies 880 foot spacing with five to six wells per zone per 640 acres consisting primarily of approximately 4,400 foot laterals. |
(3) | 653 of our 1,232 horizontal drilling locations are on acreage that we operate. We have an approximately 88% average working interest in our operated locations and an approximately 16% average working interest in our non-operated locations. |
(4) | We have included undeveloped horizontal locations only on our leasehold in Reeves and Ward counties. In addition to the 1,232 horizontal drilling locations, we have 34 gross identified vertical drilling locations on acreage that we operate in the Central Basin Platform in Ward County, Texas. |
Our 2014 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $335 million, excluding leasing and other acquisitions. In the six months ended June 30, 2014, we had incurred capital costs of approximately $160 million. We currently estimate that our 2015 capital budget for drilling, completion and recompletion will be approximately $ million. We expect that approximately % of our 2015 drilling and completion budget, or $ million, will be devoted to the drilling of horizontal wells. In 2015, we expect to allocate approximately $ million of our capital budget for the drilling and completion of operated wells and $ million for our participation in the drilling and completion of non-operated wells.
Because we operate approximately 81% of our net acreage, the amount and timing of these capital expenditures are largely subject to our discretion. We believe our approximately 88% average working interest in our operated locations, as compared to our 16% average working interest in our non-operated locations, provides us with flexibility to manage our drilling program and optimize our returns and profitability. We could choose to defer a portion of our planned 2015 capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.
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For the three months ended June 30, 2014, after giving effect to the CO2 Project Disposition (which is discussed under “Recent and Formation Transactions—Recent Acquisitions and Dispositions—CO2Project Dispositions”), our average net daily production was 5,020 Boe/d (approximately 77% oil and 23% liquids-rich natural gas). The following chart provides information regarding our quarterly production growth.
(1) | Net daily production is pro forma for the Dispositions and reflects only properties owned by us as of June 30, 2014. Please see “Recent and Formation Transactions—Recent Acquisitions and Dispositions” for a discussion of the Dispositions. |
The following table provides summary information regarding our proved reserves as of September 30, 2014, based on a reserve report prepared by NSAI, our independent reserve engineer. Of our proved reserves, approximately 38% were classified as PDP and 2% as PDNP. PUDs included in this estimate are from 47 horizontal well locations across five zones and eight vertical well locations.
Estimated Total Proved Reserves | ||||||||||||
Oil | NGLs | Natural | Total | % Oil | % Liquids(2) | % Developed | ||||||
17.0 | 1.3 | 20.7 | 21.8 | 78 | 84 | 40 |
(1) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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) | Includes oil and NGLs. |
Business Strategies
Our primary business objective is to increase stockholder value through the following strategies:
• | Grow production, cash flow and reserves by developing our extensive Delaware Basin drilling inventory. Our horizontal drilling expertise and technical acumen have enabled us to successfully drill horizontal wells across the areal extent of our acreage while targeting multiple horizontal zones. We have identified a drilling inventory of 1,232 horizontal drilling locations across five zones, which we believe can be expanded via other stacked pay zones accessible on our leasehold. Currently, we operate four horizontal drilling rigs focused on the Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp C zones, and we plan to accelerate our growth by adding a fifth horizontal drilling rig in the second quarter of 2015 and a sixth horizontal drilling rig in the second half of 2015. We plan to also target the 3rd Bone Spring and Wolfcamp B zones in our 2015 drilling program. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. |
• | Maximize returns by optimizing drilling and completion techniques and improving operating efficiency. We believe completion design combined with cost reductions are the biggest drivers affecting field-level economics. We seek to optimize our wellbore economics and consequently increase net asset |
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value growth through a methodical and continuous focus on rig efficiency, wellbore accuracy, completion design and execution. We have also improved our completion techniques by reducing perforation spacing and increasing frac stages and the amount of proppant used. We closely monitor offset operators to learn from their operational results and apply best practices to our own drilling plan to enhance returns. |
• | Maintain a high degree of operational control. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies. As the operator of 81% of our net acreage, we are able to manage (i) the timing and level of our capital spending, (ii) our development drilling strategies and (iii) our operating costs. We believe this flexibility to manage our drilling program allows us to optimize our returns and profitability. |
• | Leverage extensive acquisition experience to evaluate and pursue accretive opportunities. Our executive and core technical team has an average of approximately 26 years of industry experience. Our team has significant experience in successfully evaluating acquisition opportunities and an extensive track record of building businesses in resource plays. Furthermore, we believe our ability to understand the geology, geophysics and reservoir parameters of the rock formations in the Delaware Basin will allow us to make prudent future acquisition decisions in order to grow our resource base and maximize stockholder value. |
• | Preserve financial flexibility to pursue organic and external growth opportunities. We carefully manage our liquidity and leverage levels by regularly monitoring cash flow, capital spending and debt capacity. We intend to maintain modest leverage levels to preserve operational and strategic flexibility as well as access to the capital markets. We expect to fund our growth with cash flow from operations, availability under our revolving credit facility and capital markets offerings when appropriate. We intend to allocate capital in a disciplined manner and proactively manage our cost structure to achieve our business objectives. We expect to maintain an active hedging program that seeks to reduce our exposure to lower commodity prices and protect our cash flow. |
Our Competitive Strengths
We believe that the following strengths will help us achieve our business goals:
• | Attractively positioned in the oil-rich core of the Southern Delaware Basin. Substantially all of our current leasehold acreage is located in the oil-rich southern portion of the Delaware Basin in Reeves, Ward and Pecos counties. The majority of our properties are in Reeves County, which is the second most active county in the United States in horizontal drilling with 50 horizontal rigs running as of September 30, 2014. Since September 2013, the number of active horizontal rigs in Reeves County has increased by approximately 213%. We believe our multi-year, oil-weighted inventory of horizontal drilling locations provides attractive growth and return opportunities. As of September 30, 2014, our estimated reserves consisted of approximately 78% oil, 6% NGLs and 16% natural gas. The extensive original oil-in-place and other favorable geologic characteristics of the Southern Delaware Basin, along with the established vertical well control present across our acreage, give us a high degree of confidence in our current horizontal drilling program. |
• | Large horizontal drilling inventory across multiple pay zones. We have identified 1,232 undeveloped horizontal drilling locations in five zones across our acreage position in Reeves and Ward counties. In addition, we believe we will be able to identify additional horizontal locations as we conduct downspacing pilots, which were initiated in the fourth quarter of 2014. Of the initial 1,232 identified horizontal drilling locations, 69 are in the 3rd Bone Spring, 414 are in the Upper Wolfcamp A, 353 are in the Lower Wolfcamp A, 85 are in the Wolfcamp B and 311 are in the Wolfcamp C. Furthermore, the 2nd Bone Spring and Avalon Shale formations in the Delaware Basin may provide additional future opportunities as offset operators prove up and reduce development risk in those zones. |
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• | Our acreage has been delineated across multiple zones. Our 35 horizontal wells (33 of which we operate) span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, offset operators have continued to successfully drill horizontal wells across our five targeted zones in close proximity to our leasehold, further delineating our acreage position. |
• | Proven horizontal drilling expertise and technical acumen in the Delaware Basin. We believe our horizontal drilling experience targeting multiple pay zones in the Delaware Basin provides us with a competitive advantage. Our horizontal wells have performed in the top tier of Southern Delaware Basin operators measured on a peak 30-day average initial production rate per 1,000 lateral feet, based on data over the last twelve months from the Texas Railroad Commission. Over the last nine months, we have reduced drilling days from 57 to 41 days, and we expect improvements will continue. Additionally, we believe we have drilled the most Wolfcamp C horizontal wells in the Southern Delaware Basin, demonstrating our horizontal drilling leadership in our area of the Basin. Furthermore, our technical team has extensive experience developing resources using horizontal drilling in the Permian, Bakken and Niobrara plays over the last decade and has leveraged this experience to enhance the development of our Delaware Basin acreage. |
• | High degree of operational control. Our significant operational control allows us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility allows us to efficiently develop our current acreage. In addition, we believe communication and data exchange with offset operators will reduce the risks associated with drilling the multiple horizontal zones of our acreage. We also believe our significant level of operational control will enable us to implement drilling optimization strategies, such as pad drilling, continued reduction of spud-to-rig-release days and downspacing. We have approximately 48% of our total net acreage either held by production or under continuous drilling provisions. We believe the substantial majority of our operated Reeves and Ward county net acreage will be held by production by early 2016. |
• | Experienced and incentivized management team. With an average of 26 years of industry experience, our senior management team has a proven track record of building and running successful businesses focused on the development and acquisition of oil and gas properties. We believe our team’s experience and expertise in horizontal drilling and completions in unconventional formations across multiple resource plays provides us with a distinct competitive advantage. Additionally, our management team has a significant indirect economic interest in us through the ownership of incentive units, which provides a meaningful incentive to increase the value of our business for the benefit of all stockholders. |
• | Conservatively capitalized balance sheet and strong liquidity profile. After giving effect to this offering and the use of proceeds therefrom, we expect to have no outstanding borrowings under our revolving credit facility and approximately $ million of cash on the balance sheet. We believe the approximately $ million of availability on our revolving credit facility, cash on hand and cash flow from operations will provide us with sufficient liquidity to execute on our current capital program. |
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Our Properties
Our properties include working interests in approximately 67,800 gross (40,500 net) surface acres, substantially all of which are located in the oil-rich core of the Southern Delaware Basin, a sub-basin of the Permian Basin, in the Texas counties of Reeves, Ward and Pecos. The following table summarizes our surface acreage by county as of September 30, 2014.
Gross | Net | |||||||
County: | ||||||||
Reeves | 51,000 | 28,700 | ||||||
Ward | 6,300 | 3,600 | ||||||
Pecos | 9,900 | 7,600 | ||||||
Howard | 600 | 600 | ||||||
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Total | 67,800 | 40,500 | ||||||
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Permian Basin. The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. The Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target zones, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoirquality and historically high drilling success rates. According to the EIA, the Permian Basin is the most prolific oil producing area in the U.S., accounting for 18% of total U.S. crude oil production in 2013. Six key producing formations within the Permian Basin (Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso and Delaware) have provided the bulk of the Basin’s 60% increase in oil production since 2007. Approximately 75% of the increase came from the Wolfcamp, Bone Spring and Spraberry formations.
Delaware Basin.The present structural form of the Delaware Basin, a sub-basin of the Permian Basin, began to take shape in the early Pennsylvanian period at which time the area slowly downwarped relative to the adjacent Central Basin Platform and Northwest Shelf. This period was characterized by relatively stable marine shale and limestone deposition with periodic influxes of siliciclastics during sea-level lowstands. Stratigraphic records indicate a rapid deepening of the Delaware Basin during early Permian time. High total organic carbon marine shales, carbonate debris flows and turbidite sandstones were the predominant deposits in the Delaware Basin during this period. Subsequent burial and thermal maturation of this thick Permian succession of highly organic source and reservoir rock resulted in what we believe is evolving into a prolific oil field.
The Delaware Basin encompasses an estimated 10,039 square miles and contained over 31,000 producing wells in 2013, with production from certain wells dating back to 1924. Horizontal drilling activity has historically been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. According to Baker Hughes, four of the top six Permian Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county with 50 rigs as of September 30, 2014. The number of horizontal rigs within the Permian Basin, and specifically Reeves County, has been subject to a significant upward trend over the past year.
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As illustrated in our leasehold map below, the vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Southern Delaware Basin, primarily in the adjacent Texas counties of Reeves, Ward and Pecos.
We believe that our properties are prospective for oil and liquids-rich natural gas from multiple producing stratigraphic horizons, which we refer to as stacked pay zones. For the three months ended June 30, 2014, after giving effect to the CO2 Project Disposition, our production averaged 77% oil and 23% liquids-rich natural gas and has a greater liquids-content than other areas of the Delaware Basin.
Oil and gas production was first established in the area of our leasehold from vertical wells in the Wolfbone interval, a blend of stacked pay zones in the Permian (Wolfcampian) Wolfcamp and overlying (Leonardian) Bone Spring formations. Operators were initially drawn to this area for the thick pay section, superior rock quality and oil-rich production. The Barilla Draw field, partially coincident with our leasehold, is the source of substantial petrophysical data acquired during this vertical phase of development. This data, including 17 of our wells with advanced petrophysical logs and two of our wells with whole core, is being utilized to guide our horizontal development of the area. The vertical development has resulted in a better understanding of our leasehold’s geology relative to other parts of the Basin and has not caused significant depletion. Depth to the top of the Wolfcamp from a representative well central to our leasehold is approximately 10,500 feet. The gross thickness of the potential pay section from the top of the Bone Spring through the base of the Wolfcamp C is approximately 3,300 feet, an attractive thickness for development with multiple horizontal landing zones. We believe that the combination of these conditions will allow us to achieve superior results during the development of our leasehold.
Our initial horizontal drilling, including 33 operated wells, has been widespread with locations across the majority of our leasehold. We have established commercial production in five distinct zones: the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C, across an area approximately 45 miles long by 20 miles wide. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones. Also, we have 48% of our total net acreage either held by production or under continuous drilling provisions. This has put us in a position to strategically develop our acreage with a near-term focus on high-return projects. Our previous activity, such as horizontal drilling in the Wolfcamp B and C zones, has been a catalyst for activity from offset operators. We will closely monitor this offset activity and adjust our future development plans with information and best practices learned from our peers.
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We operate approximately 81% of our net acreage and have an approximately 88% average working interest in our operated locations. This operational control gives us flexibility in development strategy and pace. We are currently running four horizontal rigs in the Delaware Basin and plan to add a fifth rig in the second quarter of 2015 and a sixth rig in the second half of 2015. Continuous improvement in operational efficiency is a major focus for us, and we have undertaken initiatives to reduce drilling costs without compromising health, safety and environment. We have reduced the spud-to-rig release time to drill and complete a horizontal well (4,000 to 4,500 foot lateral) from approximately 57 days (10 wells drilled during the second half of 2013) to approximately 41 days (13 wells drilled during the second and third quarters of 2014), thereby improving our return on capital. Our most efficient well to date, only 32 days from spud-to-rig release, was drilled in the third quarter of 2014. We expect that our contiguous acreage positions will allow us to gain operational efficiencies and cost savings through pad drilling, shared resources (water handling, tank batteries and gas gathering) and production optimization. In the future, we expect to achieve additional cost reductions and increased returns as we shift from appraisal to development.
Completion design and its effective execution are the predominant factors that dictate relative well performance in an area or zone. We have an evolving completion strategy that includes methodical adjustments of parameters, experimentation of different designs on adjacent locations with similar rock characteristics, constant monitoring and re-evaluation of results and ultimately tailoring completions to the conditions specific to an area or zone. Our completions are a hybrid fracture stimulation, a combination of slickwater and cross-linked gel, with increased stage count, increased pad volumes pumped with 100 mesh sweeps and increased total proppant volume per stage, and increased volume of white sand with a tail of resin-coated sand. Field-level rate of return is most influenced by incremental improvements in well performance and cost savings; our philosophy is to focus on both parameters, with an emphasis on performance enhancement.
Our current drilling program is focused primarily on the Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp C zones. However, based on existing well results and our analysis of geologic and engineering data, we believe the 3rd Bone Spring and Wolfcamp B intervals are prospective across our acreage, and we also plan to target those zones in our 2015 drilling program. In addition, we plan to test various spacing pilots in the fourth quarter of 2014 and in 2015. Our current location count is based on five to six locations spaced approximately 880 feet from each other within a zone and staggered vertically in adjacent zones (as illustrated in the figure below). If downspacing pilots are successful, we may be able to add additional locations to our multi-year inventory. We also believe we have the potential to increase our inventory with additional horizontal locations in zones not currently included in our drilling program, such as the 2nd Bone Spring and Avalon Shale zones.
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NSAI, our independent petroleum engineering firm, has estimated that as of September 30, 2014, proved reserves net to our interest in our properties were approximately 21,756 MBoe, of which 38% were classified as PDP. The proved reserves are generally characterized as long-lived, with predictable production profiles.
Production Status. For the three months ended June 30, 2014, after giving effect to the CO2 Project Disposition, our average net daily production was 5,020 Boe/d (approximately 77% oil and 23% liquids-rich natural gas). During 2013, after giving effect to the Dispositions, our average net daily production was 1,701 Boe/d (approximately 79% oil and 21% liquids-rich natural gas). As of September 30, 2014, we produced from 35 horizontal and 76 vertical wells.
Facilities. We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production growth. We accomplish this goal primarily through contractual arrangements with third party service providers. Our facilities located on our properties are generally in close proximity to our well locations and include storage tank batteries, oil/gas/water separation equipment and pumping units. For gas gathering and processing, we have infrastructure in place that spans the heart of our leasehold. Our gas is processed at a cryogenic plant that is centrally located in our area of operations. Presently, there is excess capacity in the system of our primary gatherer with whom we have a long-term agreement and benefit from priority producer status as the anchor tenant.
Recent and Future Activity. After giving effect to the Dispositions, a total of 31 gross (13 net) wells were drilled and completed on our acreage during 2013. Of these wells, 11 gross (9 net) wells were horizontal wells. During the nine months ended September 30, 2014, 31 gross (23 net) wells were drilled and completed on our acreage. Of these wells, 22 gross (19 net) wells were horizontal wells. Four horizontal rigs and one vertical rig are scheduled to be active during the fourth quarter of 2014, during which an additional seven wells are scheduled to be drilled and completed. In 2015, we plan to add a fifth horizontal rig in the second quarter and a sixth horizontal rig in the second half of the year. We forecast that operated horizontal wells and non-operated horizontal wells will be drilled on our properties in 2015.
As of September 30, 2014, we had identified 1,232 gross horizontal drilling locations in the 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C horizontal zones across our Delaware Basin acreage based on spacing of five to six wells per zone per 640 acre section. In addition, as of September 30, 2014, we had identified 34 gross vertical drilling locations that we operate on our Central Basin Platform acreage based on 40-acre spacing, which does not include any undeveloped vertical locations on our Delaware Basin leasehold. Also, such vertical drilling location count does not include any undeveloped vertical or horizontal locations on our leasehold in Pecos and Howard counties. In this prospectus, we define identified gross drilling locations as locations on operated and non-operated leasehold specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our combined horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations that we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.
Oil and Natural Gas Data
Proved Reserves
Evaluation and Review of Proved Reserves. Our proved reserve estimates as of September 30, 2014 were prepared by Netherland, Sewell & Associates, Inc. (NSAI), our independent petroleum engineers. The technical
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persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of the independent petroleum engineering firm’s proved reserve report as of September 30, 2014 is included as an exhibit to the registration statement of which this prospectus forms a part. Our reserve report as of December 31, 2013 was prepared internally by our in-house petroleum engineers in accordance with (i) the same methodology utilized by NSAI in preparing the NSAI Report and (ii) the rules and regulations of the SEC.
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Terry Sherban, our Vice President, Reservoir Engineering, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Sherban is a petroleum engineer with 35 years of reservoir and operations experience, and our geoscience staff has an average of approximately 28 years of energy industry experience.
The preparation of our proved reserve estimates were completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
• | review and verification of historical production data, which data is based on actual production as reported by us; |
• | review of reserve estimates by Mr. Sherban or under his direct supervision; |
• | review by our Vice President, Development and Chief Executive Officer of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions; |
• | direct reporting responsibilities by our Vice President, Reservoir Engineering to our Chief Executive Officer; and |
• | verification of property ownership by our land department. |
Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of September 30, 2014 and December 31, 2013 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and
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analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting PDNP and PUD for our properties, due to the abundance of analog data.
To estimate economically recoverable proved reserves and related future net cash flows, we, in the case of our internally prepared reserve report as of December 31, 2013, and NSAI, in the case of the reserve report as of September 30, 2014, considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.
Summary of Oil and Natural Gas Reserves. The following table presents our estimated net proved oil and natural gas reserves as of September 30, 2014 and December 31, 2013, based on the proved reserve report as of September 30, 2014 by NSAI, our independent petroleum engineering firm, and our internally prepared reserve report as of December 31, 2013, respectively, in each case prepared in accordance with the rules and regulations of the SEC and after giving effect to the Combination as if it had occurred on January 1, 2013. A copy of the proved reserve report as of September 30, 2014 prepared by NSAI with respect to our properties is included as an exhibit to the registration statement of which this prospectus forms a part. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering. All of our proved reserves are located in the United States.
September 30, 2014(1) | December 31, 2013(1) | |||||||
Proved developed reserves: | ||||||||
Oil (MBbls) | 6,779 | 6,021 | ||||||
NGLs (MBbls) | 618 | 383 | ||||||
Natural gas (MMcf) | 8,328 | 4,838 | ||||||
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Total (MBoe)(2) | 8,786 | 7,210 | ||||||
Proved undeveloped reserves: | ||||||||
Oil (MBbls) | 10,258 | 12,489 | ||||||
NGLs (MBbls) | 655 | 143 | ||||||
Natural gas (MMcf) | 12,341 | 2,131 | ||||||
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Total (MBoe)(2) | 12,970 | 12,987 | ||||||
Total proved reserves: | ||||||||
Oil (MBbls) | 17,038 | 18,510 | ||||||
NGLs (MBbls) | 1,273 | 526 | ||||||
Natural gas (MMcf) | 20,669 | 6,969 | ||||||
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Total (MBoe)(2) | 21,756 | 20,197 |
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September 30, 2014(1) | December 31, 2013(1) | |||||||
Oil and Natural Gas Prices: | ||||||||
Oil—NYMEX—WTI per Bbl | $ | 95.56 | $ | 95.96 | ||||
Natural gas and NGL—NYMEX—Henry Hub per MMBtu | $ | 4.24 | $ | 3.67 |
(1) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. |
(2) | One Boe is equal to six Mcf of natural gas or one Bbl of oil based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
The changes from December 31, 2013 estimated proved reserves to September 30, 2014 estimated proved reserves reflect production during this period of approximately MBoe, additions of approximately MBoe attributable to new locations resulting from the strategic drilling of wells to delineate our acreage position and the sale 13,286 Mboe of reserves to an unrelated party in the CO2 Project Disposition.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors” appearing elsewhere in this prospectus.
Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus and the proved reserve report as of September 30, 2014, which is included as an exhibit to the registration statement of which this prospectus forms a part.
PUDs
Year Ended December 31, 2013
As of December 31, 2013, our PUDs totaled 12,489 MBbls of oil, 2,131 MMcf of natural gas and 143 MBbls of NGLs, for a total of 12,987 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes in PUDs that occurred during 2013 were primarily due to (i) additions of approximately 4,038 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position and (ii) the conversion of approximately 402 MBoe attributable to PUDs into proved developed reserves.
During the twelve months ended December 31, 2013, we spent $7.5 million to convert PUDs to proved developed reserves and $144.0 million to convert non-proved reserves to proved developed reserves.
All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.
As of December 31, 2013, 2% of our total proved reserves were classified as PDNP.
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Nine Months Ended September 30, 2014
As of September 30, 2014, our PUDs totaled 10,258 MBbls of oil, 655 MBbls of NGLs and 12,341 MMcf of natural gas, for a total of 12,970 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes in PUDs that occurred during the nine months ended September 30, 2014 were primarily due to (i) the sale of 10,806 MBoe of reserves categorized as PUD to an unrelated party in the CO2 Project Disposition, (ii) the addition of 10,848 MBoe attributable to new PUD locations resulting from the strategic drilling of wells to delineate our acreage position and (iii) the conversion of 59 MBoe of reserves categorized as PUD as of December 31, 2013 that were converted to PDP.
During the nine months ended September 30, 2014, we spent $1.4 million to convert PUDs to proved developed reserves and $192.9 million to convert non-proved reserves to proved developed reserves.
All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.
As of September 30, 2014, 2% of our total proved reserves were classified as PDNP.
Oil and Natural Gas Production Prices and Costs
Production and Price History
The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
Our Predecessor | Pro Forma(1) | |||||||||||||||||||||||
Six Months Ended June 30, | Years Ended December 31, | Six Months Ended June 30, 2014 | Year Ended December 31, 2013 | |||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||
Production data: | ||||||||||||||||||||||||
Oil (MBbls) | 619 | 253 | 713 | 651 | ||||||||||||||||||||
Natural gas and NGLs (MMcfe) | 985 | 380 | 933 | 852 | ||||||||||||||||||||
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Total (MBoe)(2) | 783 | 316 | 869 | 793 | ||||||||||||||||||||
Average prices before effects of hedges(3): | ||||||||||||||||||||||||
Oil (per Bbl) | $ | 90.95 | $ | 86.21 | $ | 92.37 | $ | 86.34 | $ | $ | ||||||||||||||
Natural gas and NGLs (per Mcfe) | 6.38 | 4.75 | 5.26 | 4.75 | ||||||||||||||||||||
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Total (per Boe)(2) | $ | 79.92 | $ | 74.73 | $ | 81.44 | $ | 75.99 | $ | $ | ||||||||||||||
Average realized prices after effects of hedges(3): | ||||||||||||||||||||||||
Oil (per Bbl) | $ | 88.56 | $ | 64.20 | $ | 74.63 | $ | 67.18 | $ | $ | ||||||||||||||
Natural gas and NGLs (per Mcfe) | 6.38 | 4.75 | 5.26 | 4.75 | ||||||||||||||||||||
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Total (per Boe)(2) | $ | 78.03 | $ | 57.11 | $ | 66.88 | $ | 60.26 | $ | $ | ||||||||||||||
Average costs (per Boe): | ||||||||||||||||||||||||
Lease operating expenses(4) | $ | 10.42 | $ | 26.86 | $ | 22.09 | $ | 28.47 | $ | $ | ||||||||||||||
Severance and ad valorem taxes | 4.23 | 4.67 | 4.78 | 5.39 | ||||||||||||||||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 37.22 | 33.62 | 33.70 | 26.53 | ||||||||||||||||||||
Exploration and abandonment expenses | 0.00 | 0.31 | 9.85 | 13.09 | ||||||||||||||||||||
General and administrative expenses(5) | 28.97 | 21.61 | 19.38 | 8.75 | ||||||||||||||||||||
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Total | $ | 80.84 | $ | 87.07 | $ | 89.80 | $ | 82.23 | $ | $ | ||||||||||||||
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(1) | Gives effect to the Dispositions. |
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(2) | One Boe is equal to six Mcf of natural gas or one Bbl of oil 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) | Average prices shown in the table reflect prices both before and after the effects of our realized commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions. |
(4) | Average realized prices for oil are net of transportation costs. Average realized prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in our LOE. |
(5) | General and administrative expenses do not include additional expenses we would have to incur as a result of being a public company. |
Productive Wells
As of September 30, 2014, we owned an approximately 56% average working interest in 111 gross (62 net) productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.
Developed and Undeveloped Acreage
The following table sets forth information as of September 30, 2014 relating to our leasehold acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||
Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) | |||||
3,700 | 3,100 | 64,100 | 37,400 | 67,800 | 40,500 |
(1) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. |
(2) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 60 to 180 days of the expiration date, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 60 to 180 days until the entire lease is held by production. None of our vertical drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule. The following table sets forth the gross and net undeveloped acreage, as of September 30, 2014, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
Remaining 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||
1,300 | 800 | 15,000 | 9,000 | 11,600 | 6,900 | 4,900 | 3,000 | 900 | 500 |
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Pro Forma Drilling Results
The table below sets forth the results of our drilling activities for the periods indicated on a pro forma basis, giving effect to the Dispositions. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
For the Nine Months Ended September 30, | For the Year Ended December 31, | |||||||||||||||||||||||||||||||
2014 | 2013 | 2013 | 2012 | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
Exploratory Wells: | ||||||||||||||||||||||||||||||||
Productive(1) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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Total Exploratory | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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Development Wells: | ||||||||||||||||||||||||||||||||
Productive(1) | 31.0 | 22.8 | 25.0 | 9.5 | 31.0 | 13.3 | 22.0 | 8.4 | ||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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Total Development | 31.0 | 22.8 | 25.0 | 9.5 | 31.0 | 13.3 | 22.0 | 8.4 | ||||||||||||||||||||||||
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Total Wells: | ||||||||||||||||||||||||||||||||
Productive(1) | 31.0 | 22.8 | 25.0 | 9.5 | 31.0 | 13.3 | 22.0 | 8.4 | ||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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Total | 31.0 | 22.8 | 25.0 | 9.5 | 31.0 | 13.3 | 22.0 | 8.4 | ||||||||||||||||||||||||
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(1) | Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history. |
Operations
General
We are the operator of approximately 81% of our net acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. We sell all of our natural gas under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less.
We normally sell production to a relatively small number of customers, as is customary in our business. For the six months ended June 30, 2014 and the year ended December 31, 2013, Plains Marketing, L.P. accounted for 79% and 72%, respectively, of our total revenue. During such periods, no other purchaser accounted for 10% or
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more of our revenue. The loss of Plains Marketing, L.P. as a purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of Plains Marketing, L.P. as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
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Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are
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in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective.
We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.
Regulation of Production of Oil and Natural Gas
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Oil
Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
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Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has
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used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for
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which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable
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waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on August 16, 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAP programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: (i) wildcat (exploratory) and delineation gas wells; (ii) low reservoir pressure non-wildcat and non-delineation gas wells; and (iii) all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012, and from pneumatic controllers and storage vessels, effective October 15, 2013. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules in 2013 that are likely responsive
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to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels, and on August 5, 2013, the EPA issued a press release announcing that it had finalized the proposed amendment, and we anticipate that this rulemaking will be made effective by the EPA publication in the Federal Register in the very near future. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other 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, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction 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 natural gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.
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. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, in 2013 the Obama administration announced its Climate 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 natural gas industry. 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. 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 a material adverse effect on our operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in May 2013, the Bureau of Land Management of the U.S. Department of the Interior published a revised proposed rule that would impose requirements for hydraulic
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fracturing activities on federal lands, including new requirements relating to public disclosure, as well as wellbore integrity and handling of flowback water. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.
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. For example, the EPA is developing effluent limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose such standards by late 2014.
Further, in April 2012, the EPA published final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under NSPS and NESHAPS programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. Further, the rules under NESHAPS include MACT for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. The EPA received numerous requests for reconsideration of these rules and court challenges were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, in September 2013 the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.
Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources and expects to make the final report 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 and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
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 issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments 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 development activities, and perhaps even be precluded from drilling wells.
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ESA and Migratory Birds
The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
In summary, we believe we are in substantial compliance with currently applicable environmental and occupational health and safety laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2013, nor do we anticipate that such expenditures will be material in 2014.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and
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there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of September 30, 2014, we had 31 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory. Please see “Executive Compensation—Named Executive Officers” for a discussion regarding the entity that has historically employed our employees.
Legal Proceedings
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.
Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
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The following table sets forth the names, ages and titles of our directors, director nominee and executive officers.
Name | Age | Position | ||||
Ward Polzin | 52 | Chief Executive Officer and Director | ||||
George Glyphis | 44 | Vice President and Chief Financial Officer | ||||
Bret Siepman | 55 | Vice President, Development | ||||
Jamie Wheat | 44 | Vice President and Chief Accounting Officer | ||||
Roxy Forst | 58 | Vice President, Land | ||||
Tim Muniz | 35 | Vice President, Operations | ||||
Terry Sherban | 57 | Vice President, Reservoir Engineering | ||||
Sean Smith | 41 | Vice President, Geosciences | ||||
Roy Aneed | 35 | Director | ||||
David Hayes | 40 | Director | ||||
Chris Carter | 36 | Director Nominee |
Ward Polzin has served as our Chief Executive Officer since our formation and as a member of our board of directors since October 1, 2014 and has served Centennial OpCo as Chief Executive Officer since April 2014. Prior to joining Centennial OpCo, Mr. Polzin served as a Managing Director in Investment Banking at Tudor, Pickering, Holt & Co. Securities, Inc., where he spearheaded the firm’s E&P asset acquisition and divestiture practice since inception in 2008. Mr. Polzin continues to serve as a senior advisor to Tudor, Pickering, Holt & Co. Securities, Inc. From 2006 to 2007, Mr. Polzin served as the U.S. Country Manager of Enerplus Resources (USA) Corporation with a focus on Bakken shale drilling in the Williston Basin of Montana. From 2003 to 2005, Mr. Polzin served in various positions at Scotia Waterous and rose to Co-Head of U.S. Acquisitions and Divestitures. He began his career with British Petroleum in Alaska where he spent seven years in various engineering and planning roles. Mr. Polzin earned his B.S. in Petroleum Engineering from Colorado School of Mines and an M.B.A. from Rice University. He is a member of the Society of Petroleum Engineers, Western Energy Alliance and the Colorado Oil & Gas Association. Mr. Polzin is also a CFA charterholder.
The board of directors believes that Mr. Polzin’s degree and experience in petroleum engineering, as well as his business expertise, bring valuable strategic, managerial and analytical skills to the board of directors and us.
George Glyphis has served as our Vice President and Chief Financial Officer since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, Mr. Glyphis served as a Managing Director in the Oil & Gas Investment Banking practice at J.P. Morgan where his client base comprised primarily upstream and integrated oil & gas companies. In his 21 years at J.P. Morgan, Mr. Glyphis led the origination and execution of transactions including initial public offerings, equity follow-on offerings, high yield and investment grade bond offerings, corporate mergers and acquisitions, asset acquisition and divestitures, and reserve-based and corporate lending. Mr. Glyphis earned his B.A. in History from the University of Virginia.
Bret Siepman has served as our Vice President, Development since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, Mr. Siepman was Vice President, Business Development for Resolute Energy Corporation where he acted in various roles for nine years with a focus on the Rockies and the Permian Basin. Mr. Siepman previously served as the Onshore North America Exploration Manager for Kerr-McGee Corporation, Geophysicist exploring the Rockies and California for Samedan Oil Corporation and Geologist and Geophysicist for Chevron USA. Mr. Siepman earned his B.A. in Geology at the University of California, Santa Barbara and an M.S. in Geology at Colorado School of Mines. He is a member of the American Association of Petroleum Geologists, the Society of Exploration Geophysicists and is a Registered Professional Geologist in Wyoming.
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Jamie Wheat has served as our Vice President and Chief Accounting Officer since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, Ms. Wheatserved as the Vice President and Controller for Berry Petroleum Company. Ms. Wheat also held various Audit positions with KPMG. She earned a B.S. in Accounting at the University of Colorado, Boulder, and an M.S. in Accounting at the University of Colorado, Denver. Ms. Wheat is a Certified Public Accountant and is a member of the American Institute of Certified Public Accountants and COPAS – Colorado.
Roxy Forst has served as our Vice President, Land since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, from 2011 to 2013, Ms. Forst was Vice President of Land for Source Energy Partners, leading grass roots efforts in lease acquisition and drilling within the Mississippi Lime Play in Kansas. Ms. Forst also served as Manager of U.S. Lands for Enerplus Resources (USA) Corporation from 2006 to 2011. Prior to Enerplus Resources, Ms. Forst led drilling programs in the Sacramento, Permian, San Juan and Piceance Basins for Calpine Natural Gas from 1999 to 2005 and was land lead in the $1.0 billion sale of Calpine’s assets to Rosetta Resources in 2005, where she subsequently served as Director of Land. Ms. Forst attended the University of North Dakota and earned Certification in Ophthalmic Technology from the American Association of Ophthalmology. She is a Certified Professional Landman and is a member of the AAPL and Rocky Mountain Mineral Law Foundation.
Tim Muniz has served as our Vice President, Operations since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, from August 2012 to March 2013, Mr. Muniz acted as the Operations Manager for Halcón Resources Corporation after its acquisition of GeoResources, Inc. in August 2012. From 2007 to August 2012, Mr. Muniz was the Vice President, Operations for GeoResources, Inc., where he managed the drilling, completion, production and regulatory team for GeoResources, Inc.’s northern assets (G3 Operating). Mr. Muniz was also the Operations Manager for Texas American Resources, LLC from 2005 to 2007 and managed a two-rig drilling program in the Denver Julesburg Basin. Prior to Texas American Resources, LLC, Mr. Muniz worked as an Engineering Manager for Halliburton Energy Services. Mr. Muniz earned a B.S. in Chemical Engineering from the University of Colorado. He is a member of the Society of Petroleum Engineers and the American Association of Drilling Engineers.
Terry Sherban has served as our Vice President, Reservoir Engineering since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, from 2005 to April 2011, Mr. Sherban was VP Acquisitions for Venoco, Inc., where he was involved with all aspects of acquisition divestiture and year-end reserve work. Prior to that, Mr. Sherban also worked in various oil & gas roles,including Engineer at Cabot Oil & Gas, Manager, Engineering at DEKALB Energy and Engineer at DomePetroleum. Mr. Sherban earned a B.S. in Mechanical Engineering from the University of Saskatchewan, Canada in 1979. He is a Professionally Registered Engineer in the State of Texas and the Province of Alberta. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
Sean Smith has served as our Vice President, Geosciences since our formation and has served Centennial OpCo in such capacity since July 2014. Prior to joining Centennial OpCo, Mr. Smith worked at QEP Resources as a General Manager, leading the geoscience, regulatory and reservoir engineering departments for the Williston, Powder River and Denver Julesburg Basins. Prior to QEP Resources, Mr. Smith worked at Resolute Energy Corporation as a Manager and Geologist and also worked in various geotechnical roles at Kerr-McGee and Sanchez Oil & Gas. Mr. Smith earned his B.A. in Geology from Lawrence University. He is licensed with the Texas Board of Professional Geoscientists and is a member of the American Association of Petroleum Geologists.
Roy Aneed has served as a member of our board of directors since November 2014. Mr. Aneed has been employed by Natural Gas Partners since June 2007 and currently serves as Managing Director and Marketing & Business Development Committee co-chair. Prior to joining Natural Gas Partners, from approximately 2003 to 2007, Mr. Aneed worked as a Senior Associate at Graham Partners, Inc., a middle market buyout fund based outside of Philadelphia, Pennsylvania focused on U.S. manufacturing companies. Prior to 2003, Mr. Aneed was
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an analystwith the Investment Banking division of Citigroup in New York. Since 2012, Mr. Aneed has served as a directorof Triangle Petroleum Corporation and as a member of its compensation committee and nominating andcorporate governance committee. In 2001, Mr. Aneed received a B.S. in Economics from the Wharton School ofFinance at the University of Pennsylvania with concentrations in Finance and Management as well as a minor in European History.
The board of directors believes that Mr. Aneed’s significant financial and transactional background in the energy industry will bring important and valuable skills to the board of directors.
David Hayes has served as a member of our board of directors since November 2014. Mr. Hayes joined Natural Gas Partners in 1998 and was promoted to Managing Director in 2008. He also currently serves as Director of Corporate Finance for Natural Gas Partners. Prior to joining Natural Gas Partners, Mr. Hayes was a member of Merrill Lynch’s Energy Investment Banking group in Houston, Texas, where he focused on mergers and acquisitions and financing in the exploration and production and natural gas pipeline industries. Since 2011, Mr. Hayes has served as a director of the general partner of Eagle Rock Energy Partners L.P. Mr. Hayes received a B.A. in Economics, magna cum laude, in 1996 from Rice University, where he was elected to the Phi Beta Kappa scholastic honor society, and an M.B.A. in 2002 from Harvard Business School.
The board of directors believes that Mr. Hayes’s wealth of industry-specific transactional skills and experience will bring important and valuable skills to the board of directors.
Chris Carter will be appointed to our board of directors in connection with the consummation of this offering. Mr. Carter is a Managing Director of Natural Gas Partners. Prior to joining Natural Gas Partners in 2004, Mr. Carter was an analyst with Deutsche Bank’s Energy Investment Banking group in Houston, where he focused on financing and merger and acquisition transactions in the oil and gas and oilfield services industries. From 2013 to 2014, Mr. Carter served as a director of Rice Energy, Inc. In addition, since April 2014, Mr. Carter has served as a director of Parsley Energy, Inc. and as a member of its compensation committee and nominating and corporate governance committee. Mr. Carter received a B.B.A. and an M.P.A. in Accounting, summa cum laude, in 2002 from the University of Texas, where he was a member of the Business Honors Program. He received an M.B.A. in 2008 from Stanford University, where he graduated as an Arjay Miller Scholar.
The board of directors believes that Mr. Carter’s considerable financial and energy investment banking experience will bring important and valuable skills to the board of directors.
There are no family relationships among any of our directors or executive officers.
Board of Directors
Upon the closing of this offering, it is anticipated that we will have five directors.
We intend to appoint independent directors to our board of directors contemporaneously with and following the completion of this offering. We also expect that our board of directors will review the independence of our current directors using the independence standards of the NYSE.
In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board of directors to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.
Status as a Controlled Company
Because the Existing Investors will collectively beneficially own a majority of our outstanding common stock following the completion of this offering, we expect to be a controlled company under NYSE corporate
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governance standards. A controlled company need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and governance committees. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.
If at any time we cease to be a controlled company, we will take all action necessary to comply with the NYSE rules, including appointing a majority of independent directors to our board of directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period. We will cease to qualify as a controlled company once the Existing Investors cease to control a majority of our voting stock.
Initially, our board of directors will consist of a single class of directors each serving one year terms. After the Existing Investors no longer beneficially own or control more than 50% of the voting power of our issued and outstanding common stock, our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three year terms, and such directors will be removable only for “cause.”
Committees of the Board of Directors
Upon the conclusion of this offering, we intend to have an audit committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.
Audit Committee
We will establish an audit committee prior to the completion of this offering. We anticipate that following completion of this offering, our audit committee will consist of at least one director who will be independent under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. We anticipate that at least one of our independent directors will satisfy the definition of “audit committee financial expert.”
This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.
Code of Business Conduct and Ethics
Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.
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Corporate Governance Guidelines
Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.
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Named Executive Officers
We are currently considered an emerging growth company for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are those individuals serving as our principal executive officer and our two other most highly compensated executive officers who were serving as executive officers at the end of the last completed fiscal year. No executive officer, other than our Chief Executive Officer, had compensation that exceeded $100,000 for our last completed fiscal year. As a result, our only named executive officer for fiscal year 2013 is Ward Polzin, our Chief Executive Officer.
Name | Principal Position | |
Ward Polzin | Chief Executive Officer |
During 2013 and to date in 2014, our executive officers have been employees of Centennial Resource Management, LLC, a wholly-owned subsidiary of Centennial HoldCo, and provide services to Centennial HoldCo and Centennial OpCo pursuant to management services agreements between such entities. Prior to the completion of this offering, Centennial Resource Management, LLC will be merged with and into Centennial OpCo and our executive officers and the other employees providing services to us will become employees of Centennial OpCo.
2013 Summary Compensation Table
The following table summarizes, with respect to our named executive officer, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2013.
Name and Principal Position | Year | Salary ($)(1) | Bonus ($)(2) | Option Awards ($)(3) | Total ($) | |||||||||||||||
Ward Polzin, | ||||||||||||||||||||
Chief Executive Officer | 2013 | $ | 89,567 | $ | 200,000 | $ | 0 | $ | 289,567 |
(1) | Reflects the period beginning on August 1, 2013, Mr. Polzin’s date of hire, and ending on December 31, 2013. |
(2) | Reflects the discretionary bonus paid to Mr. Polzin for 2013 services. |
(3) | Mr. Polzin received an award of “incentive units” pursuant to the Limited Liability Company Agreement of Centennial HoldCo (as amended from time to time, the “LLC Agreement”) in 2013. The incentive units are intended to constitute “profits interests” and represent actual (non-voting) equity interests in Centennial HoldCo that have no value for tax purposes on the date of grant but are designed to gain value only after the underlying assets have realized a certain level of growth and return to those persons who hold certain other classes of Centennial HoldCo’s equity. We believe that, despite the fact that the incentive units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as “options” for purposes of the SEC’s executive compensation disclosure rules under the definition provided in Item 402(m)(5)(i) of Regulation S-K since these awards have “option-like features.” The amount reflected in this column for Mr. Polzin reports the value of the incentive units at the grant date based upon the probable outcome of the applicable performance conditions, determined as of the grant date under ASC 718, which was $0, because the performance conditions related to these awards were not deemed probable of achievement at the time of grant in 2013. The incentive units are not designed with a threshold, target or maximum potential payout level; however, our best estimate of the aggregate grant date fair value of Mr. Polzin’s incentive units that could have been reported under |
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ASC 718 if the applicable performance conditions had been deemed probable to occur at the grant date would have been $2.2 million. Further information regarding the assumptions used in the valuation of these incentive units is included in Note 10—Incentive Compensation to our Condensed Consolidated and Combined Financial Statements and under “—Narrative Disclosures—Incentive Units” below. |
Outstanding Equity Awards at 2013 Fiscal Year-End
The following table reflects information regarding outstanding incentive units held by our named executive officer as of December 31, 2013. As the incentive units are equity interests in Centennial HoldCo, following this offering, the incentive units held by the named executive officer will not relate directly to our securities, and we will not be financially or otherwise responsible for distributions or settlements relating to such incentive units.
Name | Option Awards (1) | |||||||||||||||
Number of Securities Underlying Unexercised Options, Unexercisable (#) | Number of Securities Underlying Unexercised Options, Exercisable (#) | Option Exercise Price ($) | Option Expiration Date | |||||||||||||
Ward Polzin,Chief Executive Officer | ||||||||||||||||
Tier I Units | 330,000 | 0 | N/A | N/A | ||||||||||||
Tier II Units | 330,000 | 0 | N/A | N/A | ||||||||||||
Tier III Units | 330,000 | 0 | N/A | N/A | ||||||||||||
Tier IV Units | 330,000 | 0 | N/A | N/A | ||||||||||||
Tier V Units | 330,000 | 0 | N/A | N/A |
(1) | The incentive units are divided into five tiers, each of which has a separate distribution threshold and vesting schedule. Awards reflected as “Unexercisable” are incentive units that have not yet vested, and awards reflected as “Exercisable” are incentive units that have vested, but have not yet been settled. For a description of how and when the incentive units could become vested and when such awards could begin to receive payments, see “—Narrative Disclosures—Incentive Units.” Additional information regarding the incentive units is also provided in footnote (3) to the 2013 Summary Compensation Table above. |
Narrative Disclosures
Employment, Severance or Change in Control Agreements
We historically have not maintained any employment, severance or change in control agreements with our named executive officer. In addition, our named executive officer is not entitled to any payments or other benefits in connection with a termination of his employment or a change in control, other than with respect to incentive units as described below under “—Incentive Units.”
Retirement Benefits
We have not maintained, and do not currently intend to maintain, a defined benefit pension plan or nonqualified deferred compensation plan. Instead, our employees, including the named executive officer, may participate in a retirement plan intended to provide benefits under section 401(k) of the Code (the “401(k) Plan”) pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. We provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the 401(k) Plan. Employees are immediately 100% vested in the matching contributions made to their 401(k) Plan account and are always 100% vested in the employee contributions they make to their 401(k) Plan account. Employees may generally receive a distribution of the vested portion of their 401(k) Plan account upon (i) a termination of employment, (ii) normal retirement, (iii) disability or (iv) death.
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Incentive Units
Mr. Polzin received an award of incentive units in Centennial HoldCo, or profits interests that represent actual (non-voting) equity interests in Centennial HoldCo, in 2013 in order to provide him with the ability to benefit from the growth in our operations and business. The incentive units are divided into five tiers, with each tier currently comprised of one tranche. A potential payout for each tranche will occur when a certain specified level of cumulative cash distributions has been received by the capital interest holding members of Centennial HoldCo. Tier I units and Tier II units each vest in five equal annual installments beginning on the first anniversary of the applicable date of grant, although such vesting will be fully accelerated upon the occurrence of either (i) (a) with respect to the Tier I units, satisfaction of the payment threshold established for the Tier I units or (b) with respect to the Tier II units, satisfaction of the payment threshold established for the Tier II units or (ii) with respect to both Tier I units and Tier II units, a “Fundamental Change” (as defined below). Tier III units, Tier IV units and Tier V units each vest only upon satisfaction of the payment threshold established for the applicable tier. All incentive units that have not yet vested according to their applicable vesting requirements will automatically be forfeited and become null and void at the time a named executive officer’s employment is terminated for any reason; provided, however, that, prior to such forfeiture, solely with respect to any unvested incentive units that are Tier I or Tier II units, the named executive officer will vest, immediately prior to his termination of employment, as to a pro rata amount of such unvested incentive units determined by multiplying the number of incentive units that would vest on the next annual vesting date by a fraction with a numerator equal to the number of full months that have elapsed since the most recent vesting date and a denominator of 12, with such pro rata amount rounded to the closest whole number. If a named executive officer’s employment is terminated for “cause” (as defined below), or the named executive officer resigns or terminates the service relationship early (each, a “voluntary termination”), all vested incentive units will be forfeited at the time of the termination. In the event that a named executive officer’s employment is terminated other than (i) for cause or (ii) due to a voluntary termination, the named executive officer will retain all vested incentive units following such termination. For purposes of the foregoing, a named executive officer’s termination of employment means the termination of such named executive officer’s employment with us, Centennial HoldCo and all of its “Affiliates” (as defined in the LLC Agreement).
A “Fundamental Change” is generally defined in the LLC Agreement as the occurrence of any of the following events: (i) (a) Centennial HoldCo merges or consolidates with or into, or enters into any similar transaction with, any person other than one of Centennial HoldCo’s Affiliates or a “Member” or a “Related Party” (each quoted term as defined in the LLC Agreement); (b) Centennial HoldCo’s outstanding interests are sold or exchanged in a single transaction, or a series of related transactions, to any person other than one of Centennial HoldCo’s Affiliates or a Member or a Related Party; or (c) Centennial HoldCo sells, leases, licenses or exchanges, or agrees to sell, lease, license or exchange, all or substantially all of Centennial HoldCo’s assets to a person that is not one of Centennial HoldCo’s Affiliates or a Member or a Related Party, provided that in the case of any such transaction described in (a), (b) or (c), the individuals that served as members of Centennial HoldCo’s board of managers before the consummation of such transaction cease to constitute at least a majority of the members of the board or analogous managing body of the surviving or acquiring entity immediately following completion of such transaction; (ii) any person or group (other than one of Centennial HoldCo’s Affiliates or a Member or a Related Party) purchases or otherwise acquires the right to vote or dispose of securities of Centennial HoldCo representing 50% or more of the total voting power of all outstanding voting securities of Centennial HoldCo, unless the transaction was approved by Centennial HoldCo’s board of managers; or (iii) Centennial HoldCo is dissolved and liquidated.
A termination for “cause” is generally defined in the LLC Agreement to occur upon a named executive officer’s: (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to Centennial HoldCo or its Affiliates or involving acts of theft, fraud, embezzlement, moral turpitude, or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the named executive officer’s duties in a manner that materially and adversely affects the performance of such duties; (iii) malfeasance in the conduct of the named executive officer’s duties, including but not limited to (a) misuse or diversion of funds of
Centennial HoldCo or its Affiliates, (b) embezzlement or (c) misrepresentations or concealments on any written
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reports submitted to Centennial HoldCo or its Affiliates; (iv) violation of the Voting and Transfer Restriction Agreement (as defined in the LLC Agreement) or the named executive officer’s confidentiality and noncompete agreement; or (v) failure to perform the duties of the named executive officer’s employment relationship with us, Centennial HoldCo or its Affiliates, or failure to follow or comply with the reasonable and lawful written directives of our board of directors, Centennial HoldCo’s board of managers or the board of one of its Affiliates which the named executive officer is employed with, in either case, after the named executive officer shall have been informed, in writing, of such failure and given a period of not less than 60 days to remedy the failure.
We do not expect that this offering will result in a Fundamental Change, and as of the date of this filing, no tier of incentive units has received a payout. Because we are not a party to the LLC Agreement, we cannot be certain that the terms of the incentive units or the LLC Agreement will remain the same in the future. As a result, the foregoing description of the incentive units is qualified in its entirety by reference to the LLC Agreement, as may be amended from time to time.
Compensation of Directors
Centennial Resource Development, Inc., the issuer of common stock in this offering, and its board of directors (hereinafter referred to as “our board of directors”) were recently formed in October 2014 and November 2014, respectively, and, as such, no obligations with respect to compensation for directors have been accrued or paid for any periods prior to such formation date. Individuals serving on the boards of managers of our predecessor did not receive any compensation for their services on such boards of managers during fiscal year 2013.
Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interest of these directors with our stockholders.
We are reviewing the non-employee director compensation packages provided by certain peer companies and intend to implement a non-employee director compensation program in connection with this offering.
Directors who are also our employees will not receive any additional compensation for their service on our board of directors.
We expect that each director will be reimbursed for (i) travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees; (ii) travel and miscellaneous expenses related to such director’s participation in general education and orientation program for directors; and (iii) travel and miscellaneous expenses for each director’s spouse who accompanies a director to attend meetings and activities of our board of directors or any of our committees.
2014 Long Term Incentive Plan
Prior to the completion of this offering, we anticipate that our board of directors will adopt a long-term incentive plan for employees, consultants and directors. Our named executive officers and directors will be eligible to participate in this plan, which will become effective upon the consummation of this offering. We anticipate that the long-term incentive plan, which we refer to herein as the “2014 Long-Term Incentive Plan” or the “Plan,” will provide for the grant of restricted stock, options, phantom stock, bonus stock, stock appreciation rights, performance awards, annual incentive awards, and other stock-based awards intended to align the interests of participants with those of our stockholders. The following description of the Plan is based on the form we anticipate adopting, but the Plan has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final Plan once adopted.
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Administration. We anticipate that the Plan will be administered by our board of directors, or the “Plan Administrator. The Plan Administrator will have the authority to, among other things, designate participants under the Plan, determine the type or types of awards to be granted to a participant, determine the number of shares of our common stock to be covered by awards, determine the terms and conditions applicable to awards and interpret and administer the Plan. The Plan Administrator may terminate or amend the Plan at any time with respect to any shares of our common stock for which a grant has not yet been made. The Plan Administrator also has the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of shares of our common stock that may be granted, subject to stockholder approval as required by any exchange upon which our common stock is listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant.
Number of Shares. Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event, we anticipate that the number of shares available for delivery pursuant to awards granted under the Plan will not exceed shares of common stock. There is no limit on the number of awards that may be granted and paid in cash. Shares subject to an award under the Plan that are canceled, forfeited, exchanged, settled in cash or otherwise terminated, including withheld to satisfy exercise prices or tax withholding obligations, are available for delivery pursuant to other awards. The shares of our common stock to be delivered under the Plan will be made available from authorized but unissued shares, shares held in treasury, or previously issued shares reacquired by us, including by purchase on the open market.
Restricted Stock. A restricted stock grant is an award of common stock that vests over a period of time and that during such time is subject to forfeiture. The Plan Administrator may make grants of restricted stock under the Plan to participants containing such terms as the Plan Administrator shall determine. The Plan Administrator will determine the period over which restricted stock granted to participants will vest. The Plan Administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Dividends made on restricted stock may or may not be subjected to the same vesting provisions as the restricted stock.
Options. An option is a right to purchase shares of common stock at a specified price during specified time periods. The Plan will permit the grant of options covering our common stock. The Plan Administrator may make option grants under the plan to participants containing such terms as the Plan Administrator shall determine. Options will have an exercise price that may not be less than the fair market value of our common stock on the date of grant. Options granted under the Plan can be either incentive options (within the meaning of section 422 of the Code), which have certain tax advantages for recipients, or non-qualified options. Options granted will become exercisable over a period determined by the Plan Administrator. No option will have a term that exceeds ten years. The availability of options is intended to furnish additional compensation to participants and to align their economic interests with those of common stockholders.
Phantom Stock Awards. A phantom stock award is a notional share that entitles the grantee to receive shares of common stock following the vesting of the phantom stock award or, in the discretion of the Plan Administrator, cash equivalent to the value of the number of shares of common stock subject to the award. The Plan Administrator may make grants of phantom stock under the plan to participants containing such terms as the Plan Administrator shall determine. The Plan Administrator will determine the period over which phantom stock granted to participants will vest and the times in which phantom stock awards will be paid.
The Plan Administrator, in its discretion, may grant tandem dividend equivalent rights with respect to phantom stock awards that entitle the holder to receive cash equal to any cash dividends made on our common stock while the phantom stock award is outstanding.
Bonus Stock. The Plan Administrator, in its discretion, may also grant to participants shares of common stock that are not subject to forfeiture. The Plan Administrator can grant bonus stock without requiring that the recipient pay any remuneration for the shares.
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Stock Appreciation Rights. The Plan will permit the grant of stock appreciation rights. A stock appreciation right is an award that, upon exercise, entitles participants to receive the excess of the fair market value of our common stock on the exercise date over the grant price established for the stock appreciation right on the date of grant. Such excess will be paid in cash or common stock. The Plan Administrator may make grants of stock appreciation rights under the Plan to participants containing such terms as the Plan Administrator shall determine. Stock appreciation rights will have a grant price that may not be less than the fair market value of our common stock on the date of grant. In general, stock appreciation rights granted will become exercisable over a period determined by the Plan Administrator.
Performance Awards. A performance award is a right to receive all or part of an award granted under the Plan based upon performance criteria specified by the Plan Administrator. The Plan Administrator will determine the period over which certain specified company or individual goals or objectives must be met. The performance award may be paid in cash, shares of our common stock or other awards or property, in the discretion of the Plan Administrator.
Annual Incentive Awards. An annual incentive award is a conditional right to receive a cash payment, shares or other award unless otherwise determined by the Plan Administrator, after the end of a specified year. The amount potentially payable will be based upon the achievement of performance goals established by the Plan Administrator.
Other Cash Awards. Cash awards may also be granted by the Plan Administrator under the Plan, in its discretion. Cash awards may be subject to time or performance-based vesting conditions, or no conditions whatsoever.
Other Stock-Based Awards. The Plan Administrator, in its discretion, may also grant to participants an award denominated or payable in, referenced to, or otherwise based on or related to the value of our common stock.
Tax Withholding. At our discretion, and subject to conditions that the Plan Administrator may impose, a participant’s minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of shares issuable pursuant to the award based on the fair market value of the shares.
Anti-Dilution Adjustments. If any “equity restructuring” event occurs that could result in an additional compensation expense under ASC 718 if adjustments to awards with respect to such event were discretionary, the Plan Administrator will equitably adjust the number and type of shares covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the Plan Administrator will adjust the number and type of shares with respect to which future awards may be granted. With respect to a similar event that would not result in a ASC 718 accounting charge if adjustment to awards were discretionary, the Plan Administrator shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the Plan Administrator makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of shares available under the Plan and the kind of shares or other securities available for grant under the Plan. Furthermore, in the case of (i) a subdivision or consolidation of the common stock (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the Plan, as appropriate, with respect to the maximum number of shares available under the Plan, the number of shares that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.
Change in Control. Upon a “change in control” (as defined in the Plan), the Plan Administrator may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability
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or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the Plan Administrator deems appropriate to reflect the change of control.
Termination of Employment or Service. The consequences of the termination of a participant’s employment, consulting arrangement, or membership on the board of directors will be determined by the Plan Administrator in the terms of the relevant award agreement.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth the beneficial ownership of our common stock that, upon the consummation of this offering and the Combination, will be owned by:
• | each of the selling stockholders; |
• | each person known to us to beneficially own more than 5% of any class of our outstanding common stock; |
• | each member of our board of directors; |
• | our named executive officer; and |
• | all of our directors and executive officers as a group. |
All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, selling stockholders, directors or named executive officer, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Centennial Resource Development, Inc., 1401 17th Street, Suite 1000, Denver, Colorado 80202.
To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from the selling stockholders.
Shares Beneficially Owned Before this Offering | Shares Offered Hereby | Shares Beneficially Owned After this Offering (Assuming No Exercise of the Underwriters’ Option to Purchase Additional Shares) | Shares Beneficially Owned After this Offering (Assuming the Underwriters’ Option to Purchase Additional Shares is Exercised in Full) | |||||||||||||||||
Name of Beneficial Owner(1) | Number | Percentage | Number | Percentage | Number | Percentage | ||||||||||||||
Selling Stockholders: | ||||||||||||||||||||
Centennial Resource Development, LLC(2) | % | % | % | |||||||||||||||||
Celero Energy Company, LP(3) | % | % | % | |||||||||||||||||
Directors and Named Executive Officer: | ||||||||||||||||||||
Roy Aneed | % | % | % | |||||||||||||||||
David Hayes | % | % | % | |||||||||||||||||
Ward Polzin | % | % | % | |||||||||||||||||
Directors and Executive Officers as a Group (11 Persons) | % | % | % |
(1) | The amounts and percentages of common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock, except to the extent this power may be shared with a spouse. |
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(2) | The board of managers of Centennial HoldCo has voting and dispositive power over these shares. The board of managers of Centennial HoldCo consists of Ward Polzin (our Chief Executive Officer and one of our directors), Bret Siepman (our Vice President, Development), Roy Aneed (one of our directors), Chris Carter (our director nominee) and David Hayes (one of our directors). None of such persons individually have voting and dispositive power over these shares, and the board of managers of Centennial HoldCo acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Centennial HoldCo. NGP X US Holdings, L.P. (“NGP X US Holdings”) owns 99% of Centennial HoldCo, and certain members of our management team own the remaining 1%. Certain members of our management team and certain of our employees also own incentive units in Centennial HoldCo. Please see “Executive Compensation—Narrative Disclosures—Incentive Units” for more information on the incentive units. As a result, NGP X US Holdings may be deemed to indirectly beneficially own the shares held by Centennial HoldCo. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP, L.L.C. (the sole general partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general partner of NGP Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. GFW X, L.L.C. has delegated full power and authority to manage NGP X US Holdings to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. |
(3) | Celero Energy Management, LLC, the general partner of Celero (“Celero GP”), has voting and dispositive power over these shares. The board of managers of Celero GP consists of David Hayes (one of our directors), Bruce Selkirk and Christopher Ray. None of such persons individually have voting and dispositive power over these shares, and the board of managers of Celero GP acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Celero GP. Natural Gas Partners VIII, L.P. (“NGP VIII”) owns 94.7% of the membership interests of Celero GP, and the remaining 5.3% is held by certain members of Celero’s management team and other minority owners. As a result, NGP VIII may be deemed to indirectly beneficially own these shares. NGP VIII disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. G.F.W. Energy VIII, L.P. (the sole general partner of NGP VIII) and GFW VIII, L.L.C. (the sole general partner of G.F.W. Energy VIII, L.P.) may each be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. GFW VIII, L.L.C. has delegated full power and authority to manage NGP VIII to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. |
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RECENT AND FORMATION TRANSACTIONS
Recent Acquisitions and Dispositions
CO2 Project Disposition
In May 2014, we conveyed certain oil and gas properties in Chaves County, New Mexico pursuant to which we had pursued a tertiary recovery project utilizing CO2 to increase production on such properties, including wells that produced 378 net Boe/d in the first half of 2014, for net cash proceeds of approximately $59.3 million.
Wolfbone Disposition
In October 2013, we conveyed approximately 1,000 net acres in the Delaware Basin portion of the Permian Basin, including approximately 187 non-operated wells that produced approximately 200 net Boe/d in the first half of 2013, for net cash proceeds of approximately $28.7 million.
Resolute Disposition
Pursuant to a transaction that closed in December 2012, we sold our (i) non-operated working interests in approximately 1,300 net acres in Howard County, Texas, including 23 producing wells that produced a net 377 Boe/d in the third quarter of 2012, (ii) 2,767 net acres in Lea County, New Mexico, including 39 producing wells that produced a net 833 Boe/d in the third quarter of 2012 and (iii) 2,455 additional net acres in the Permian Basin, including wells that produced approximately 208 net Boe/d in the third quarter of 2012, for net cash proceeds of approximately $111.9 million.
Corporate Formation Transactions
The Combination
Centennial OpCo (formerly known as Atlantic Energy Holdings, LLC) is an independent oil and natural gas company formed on August 30, 2012 by its management members, third-party investors and an affiliate of NGP, a family of energy-focused private equity investment funds founded in 1988 with aggregate committed capital under management since inception of over $14.5 billion. Subsequently, in April 2014, NGP contributed its membership interests in Centennial OpCo to Centennial HoldCo, which was formed by NGP and certain members of management. Centennial HoldCo is a holding company with no independent operations apart from its ownership interests in Centennial OpCo. On or before August 2014, all of the other members of Centennial OpCo (including its management members) sold their membership interests in Centennial OpCo to Centennial OpCo or Centennial HoldCo for cash. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo.
Celero is an independent oil and natural gas company that was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Celero was formed by its general partner, Celero Energy Management, LLC, its management team and NGP. Beginning in 2006, through a series of acquisitions of undeveloped acreage and producing properties as well as through development drilling and other activities, Celero focused on a number of project areas in the Permian Basin, including (i) oil and gas properties primarily located in Howard County, Texas and Lea County, New Mexico that were subsequently sold to Resolute in December 2012 in the Resolute Disposition, (ii) oil and gas properties in Chaves County, New Mexico pursuant to which Celero pursued a tertiary recovery project utilizing CO2 to increase production on such properties that were subsequently sold to an unrelated third party in May 2014 in the CO2Disposition and (iii) oil and gas properties located in Reeves, Ward and Pecos counties in West Texas targeting the Delaware Basin portion of the Permian Basin, a portion of which was sold in October 2012 in the Wolfbone Disposition. Following the Dispositions, Celero owned non-operated interests in oil and natural gas properties in the Delaware Basin in which Centennial OpCo also has a working interest and substantially all of which are operated by Centennial OpCo.
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On October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo. Immediately following the completion of the Combination, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
Our Corporate Reorganization
Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, each of Centennial HoldCo and Celero will contribute all of their interests in Centennial OpCo to Centennial Resource Development, Inc., the issuer of common stock in this offering, in exchange for shares of common stock in Centennial Resource Development, Inc. As a result, Centennial Resource Development, Inc. will become the holding company for Centennial OpCo.
During 2013 and to date in 2014, our executive officers have been employees of Centennial Resource Management, LLC, a wholly-owned subsidiary of Centennial HoldCo, and provide services to Centennial HoldCo and Centennial OpCo pursuant to management services agreements between such entities. Prior to the completion of this offering, Centennial Resource Management, LLC will be merged with and into Centennial OpCo and our executive officers and the other employees providing services to us will become employees of Centennial OpCo.
The Existing Investors
Following our corporate reorganization, the Existing Investors will consist of the following:
Number of Shares Owned Before this Offering | Shares to be Offered in this Offering (1) | Number of Shares Owned After this Offering (1) | ||||
Existing Investor Name: | ||||||
Centennial Resource Development, LLC | ||||||
Celero Energy Company, LP | ||||||
|
|
| ||||
Total | ||||||
|
|
|
(1) | Assumes no exercise of the underwriters’ option to purchase additional shares of our common stock. |
For more information on the ownership of our common stock by our principal and selling stockholders, see “Principal and Selling Stockholders.”
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Historical Transactions with Affiliates
Resolute Disposition
As more fully described under “Recent and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition,” in December 2012, we sold all of our working interests in certain Permian Basin assets to Resolute for approximately $111.9 million and realized a $36.4 million gain on the sale. In January 2013, we recognized an additional gain of $1.5 million related to the Resolute Disposition as a result of title defects and other contingent post-closing items accrued as of December 31, 2012. As of January 2013, an affiliate of NGP, Natural Gas Partners VII, L.P. (“NGP VII”), and an affiliated co-investment fund (“NGP VII Co-Invest”) collectively own less than 5% of the total issued and outstanding shares of Resolute. Assuming full exercise of all warrants held by an entity owned by NGP VII and NGP VII Co-Invest, however, as of January 2013, NGP VII and NGP VII Co-Invest would collectively own 10.7% of Resolute. Also as of January 2013, NGP was entitled to designate one member of Resolute’s board of directors. NGP VII and NGP VII Co-Invest currently hold no shares of Resolute and are no longer entitled to designate any member of Resolute’s board of directors.
The Combination
As described under “Recent and Formation Transactions—Corporate Formation Transactions—The Combination,” on October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo. An affiliate of NGP, Natural Gas Partners VIII, L.P., owns over 90% of the membership interests in the general partner of Celero and approximately 26.3% of the limited partnership interests of Celero. Following the completion of the Combination but immediately prior to the completion of this offering, Celero will own approximately 28% of Centennial Resource Development, Inc.’s common stock. One of our directors, David Hayes, is also a director of Celero.
Corporate Reorganization
As described in “Recent and Formation Transactions—Corporate Formation Transactions—Our Corporate Reorganization,” in connection with this offering, pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, each of Centennial HoldCo and Celero will contribute all of their interests in Centennial OpCo to Centennial Resource Development, Inc., the issuer of common stock in this offering, in exchange for shares of common stock in Centennial Resource Development, Inc. Centennial OpCo is owned by NGP X, an entity affiliated with NGP, certain members of our management team and certain of our employees.
The NGP Contributions
In August 2012, an affiliate of NGP contributed approximately $75 million in cash to Centennial OpCo in exchange for 50.5% of the initial membership interests in Centennial OpCo. During 2013, the same affiliate of NGP contributed an additional $115 million to Centennial OpCo for additional membership interests in Centennial OpCo. As a result of that subsequent contribution, NGP increased its ownership in Centennial OpCo to 74.2%. In April 2014, the same affiliate of NGP contributed all of its membership interests in Centennial OpCo to Centennial HoldCo. In connection with our corporate reorganization, Centennial HoldCo will contribute such interests in Centennial OpCo to Centennial Resource Development, Inc. in exchange for shares of common stock of Centennial Resource Development, Inc.
Registration Rights Agreement
In connection with the closing of this offering, we will enter into a registration rights agreement with Centennial HoldCo and Celero. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.
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Procedures for Approval of Related Party Transactions
Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:
• | any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; |
• | any person who is known by us to be the beneficial owner of more than 5% of our common stock; |
• | any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and |
• | any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest. |
We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.
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Upon completion of this offering, the authorized capital stock of Centennial Resource Development, Inc. will consist of shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.
The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Centennial Resource Development, Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.
Common Stock
Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.
The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.
Preferred Stock
Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.
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Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law
Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.
These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.
Delaware Law
Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:
• | the transaction is approved by the board of directors before the date the interested stockholder attained that status; |
• | upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or |
• | on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder. |
We may elect to not be subject to the provisions of Section 203 of the DGCL.
Our Amended and Restated Certificate of Incorporation and Our Amended and Restated Bylaws
Provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our common stock.
Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:
• | establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws |
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specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting; |
• | provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company; |
• | provide that the authorized number of directors may be changed only by resolution of the board of directors; |
• | provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum; |
• | provide that our bylaws can be amended by the board of directors; and |
• | at any time after the Existing Investors and their respective affiliates (the “Sponsors”) no longer collectively own more than 50% of the outstanding shares of our common stock, |
• | provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting); |
• | provide our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock); |
• | provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote); |
• | provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors; and |
• | provide that the affirmative vote of the holders of at least 75% of the voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office and such removal may only be for cause. |
Corporate Opportunity
Under our amended and restated certificate of incorporation, to the extent permitted by law:
• | NGP and its affiliates have the right to, and have no duty to abstain from, exercising such right to, conduct business with any business that is competitive or in the same line of business as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us; |
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• | if NGP or its affiliates acquire knowledge of a potential transaction that could be a corporate opportunity, they have no duty to offer such corporate opportunity to us; and |
• | we have renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities. |
Forum Selection
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:
• | any derivative action or proceeding brought on our behalf; |
• | 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; |
• | any action asserting a claim against us arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or |
• | 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. |
Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.
Limitation of Liability and Indemnification Matters
Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:
• | for any breach of their duty of loyalty to us or our stockholders; |
• | for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law; |
• | for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or |
• | for any transaction from which the director derived an improper personal benefit. |
Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.
Our amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also will permit us to purchase
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insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.
Transfer Agent and Registrar
The transfer agent and registrar for our common stock is .
Listing
We intend to apply to list our common stock on the NYSE under the symbol “CDEV.”
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SHARES ELIGIBLE FOR FUTURE SALE
Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.
Sales of Restricted Shares
Upon the closing of this offering, we will have outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.
As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:
• | no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; |
• | shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension) and when permitted under Rule 144 or Rule 701; and |
• | shares will be eligible for sale, upon exercise of vested options, upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension). |
Lock-up Agreements
We, all of our directors and executive officers, the selling stockholders and certain of our stockholders and employees have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. See “Underwriting—Lock-Up Agreements” for a description of these lock-up provisions.
Rule 144
In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least sixth months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.
A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least nine months would be entitled
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to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.
Rule 701
In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.
Stock Issued Under Employee Plans
We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under our equity incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.
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MATERIAL U.S. FEDERAL INCOME AND
ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS
The following is a summary of the material U.S. federal income tax and, to a limited extent, estate tax, considerations related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below), that holds our common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Code, U.S. Treasury regulations and administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.
This summary does not address all aspects of U.S. federal income or estate taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal gift tax laws, any state, local or foreign tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):
• | banks, insurance companies or other financial institutions; |
• | tax-exempt or governmental organizations; |
• | dealers in securities or foreign currencies; |
• | traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes; |
• | persons subject to the alternative minimum tax; |
• | partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein; |
• | persons deemed to sell our common stock under the constructive sale provisions of the Code; |
• | persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan; |
• | certain former citizens or long-term residents of the United States; |
• | real estate investment trusts or regulated investment companies; and |
• | persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction. |
PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISOR WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.
Non-U.S. Holder Defined
For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common stock that is not for U.S. federal income tax purposes a partnership or any of the following:
• | an individual who is a citizen or resident of the United States; |
• | a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia; |
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• | an estate the income of which is subject to U.S. federal income tax regardless of its source; or |
• | a trust (i) whose administration is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person. |
If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner and upon the activities of the partnership. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.
Distributions
As described in the section entitled “Dividend Policy,” we do not plan to make any distributions on our common stock for the foreseeable future. However, if we do make distributions of cash or property on our common stock, those distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock.” Any such dividend paid to a non-U.S. holder on our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the dividend unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.
Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent a properly executed IRSForm W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a foreign corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items).
Gain on Disposition of Common Stock
Subject to the discussion under “—Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:
• | the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met; |
• | the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or |
• | our common stock constitutes a U.S. real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes. |
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A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.
A non-U.S. holder whose gain is described in the second bullet point above generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items) which will include such gain.
Generally, a corporation is a USRPHC if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock is regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be taxable on gain recognized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock ceased to be regularly traded on an established securities market prior to the beginning of the calendar year in which the relevant disposition occurred, all non-U.S. holders generally would be subject to U.S. federal income tax on a taxable disposition of our common stock, and a 10% U.S. withholding tax would apply to the gross proceeds from the sale of our common stock by such non-U.S. holders.
Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.
U.S. Federal Estate Tax
Our common stock beneficially owned or treated as owned by an individual who is not a citizen or resident of the United States (as defined for U.S. federal estate tax purposes) at the time of death generally will be includable in the decedent’s gross estate for U.S. federal estate tax purposes and thus may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.
Backup Withholding and Information Reporting
Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E or other appropriate version of IRS Form W-8.
Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E or other appropriate version of IRS Form W-8 and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a foreign office of a broker. However, unless such broker has documentary evidence in its records that the holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.
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Backup withholding is not an additional tax. Rather, the U.S. income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.
Additional Withholding Requirements under FATCA
Sections 1471 through 1474 of the Code, and the Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our common stock (if such disposition occurs after December 31, 2016), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners); (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification (generally on an IRS Form W-8BEN-E) identifying the direct and indirect substantial United States owners of the entity; or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes.
The rules under FATCA are new and complex. Non-U.S. holders are encouraged to consult their tax advisors regarding the implications of FATCA on an investment in our common stock.
THE FOREGOING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL GIFT TAX LAWS AND ANY STATE, LOCAL OR FOREIGN TAX LAWS AND TAX TREATIES.
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Barclays Capital Inc. is acting as the representative of the underwriters named below. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us and the selling stockholders the respective number of shares of common stock shown opposite its name below:
Underwriters | Number of Shares | |
Barclays Capital Inc. | ||
| ||
Total | ||
|
The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement, including:
• | the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased; |
• | the representations and warranties made by us and the selling stockholders to the underwriters are true; |
• | there is no material change in our business or the financial markets; and |
• | we and the selling stockholders deliver customary closing documents to the underwriters. |
Commissions and Expenses
The following table summarizes the underwriting discounts and commissions we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling stockholders for the shares.
Us | Selling Stockholders | |||||||||||||||
No Exercise | Full Exercise | No Exercise | Full Exercise | |||||||||||||
Per Share | $ | $ | $ | $ | ||||||||||||
Total (in thousands) | $ | $ | $ | $ |
The representative has advised us that the underwriters propose to offer the shares of common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per share. After this offering, the representative may change the offering price and other selling terms. Sales of the shares of common stock made outside of the United States may be made by affiliates of the underwriters.
The expenses of this offering that are payable by us and the selling stockholders are estimated to be approximately $ (excluding underwriting discounts and commissions). We have agreed to pay certain expenses incurred by the selling stockholders in connection with this offering, other than the underwriting discounts and commissions.
Option to Purchase Additional Shares
The selling stockholders have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of shares from the selling stockholders at the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than shares in connection with this offering.
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To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s percentage underwriting commitment in this offering as indicated in the table at the beginning of this Underwriting section.
Lock-Up Agreements
We, all of our directors and executive officers, certain of our stockholders and the selling stockholders have agreed or will agree that, for a period of 180 days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc., (i) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of our common stock (including, without limitation, shares of our common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of our common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for shares of our common stock (other than the stock and shares issued pursuant to employee benefit plans, qualified stock option plans or other employee compensation plans existing on the date of this prospectus or pursuant to currently outstanding options, warrants or rights not issued under one of those plans), or sell or grant options, rights or warrants with respect to any shares of our common stock or securities convertible into or exchangeable for shares of our common stock (other than the grant of options pursuant to option plans existing on the date of this prospectus); (ii) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of shares of our common stock, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of common stock or other securities, in cash or otherwise; (iii) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of our common stock or securities convertible, exercisable or exchangeable into shares of our common stock or any of our other securities (other than any registration statement on Form S-8); or (iv) publicly disclose the intention to do any of the foregoing.
Barclays Capital Inc., in its sole discretion, may release the shares of our common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release shares of our common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time. At least three business days before the effectiveness of any release or waiver of any of the restrictions described above with respect to an officer or director of ours, Barclays Capital Inc. will notify us of the impending release or waiver and we have agreed to announce the impending release or waiver by press release through a major news service at least two business days before the effective date of the release or waiver, except where the release or waiver is effected solely to permit a transfer of common stock that is not for consideration and where the transferee has agreed in writing to be bound by the same terms as the lock-up agreements described above to the extent and for the duration that such terms remain in effect at the time of transfer.
Directed Share Program
At our request, the underwriters have reserved for sale at the initial public offering price up to % of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, director nominees, business associates and related persons who have expressed an interest in purchasing common stock in this offering. All participants will be subject to a 180-day lock-up restriction as described above in “—Lock-Up Agreements.” 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. Any reserved shares of our common stock that are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares of our common stock offered by this prospectus. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with sales of the reserved shares.
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Offering Price Determination
Prior to this offering, there has been no public market for our common stock. The initial public offering price was negotiated between the representative and us. In determining the initial public offering price of our common stock, the representative considered:
• | the history and prospects for the industry in which we compete; |
• | our financial information; |
• | the ability of our management and our business potential and earning prospects; |
• | the prevailing securities markets at the time of this offering; and |
• | the recent market prices of, and the demand for, publicly traded shares of generally comparable companies. |
Indemnification
We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.
Stabilization, Short Positions and Penalty Bids
The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of our common stock, in accordance with Regulation M under the Exchange Act:
• | Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. |
• | A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in this offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in this offering. |
• | Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. |
• | Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. |
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.
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Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor any of the underwriters make any representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
Listing on the New York Stock Exchange
We intend to apply to list our common stock on the NYSE under the symbol “CDEV.”
Stamp Taxes
If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
Other Relationships
The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for us and our affiliates, for which they received or may in the future receive customary fees and expenses.
In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.
Electronic Distribution
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations. Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
Selling Restrictions
This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized; (ii) in which any person making such offer or solicitation is not qualified to do so; or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the shares of our
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common stock or possession or distribution of this prospectus or any other offering or publicity material relating to the shares of our common stock in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any shares of our common stock or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of shares of our common stock by it will be made on the same terms.
European Economic Area
In relation to each Member State of the European Economic Area that has implemented the Prospectus Directive (each, a “Relevant Member State”), an offer to the public of any common stock that are the subject of the offering contemplated herein may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:
• | to legal entities that are qualified investors as defined under the Prospectus Directive; |
• | by the underwriters to fewer than 100, or, if the Relevant Member State has implemented the relevant provisions of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representative of the underwriters for any such offer; or |
• | in any other circumstances falling within Article 3(2) of the Prospectus Directive, |
provided that no such offer of common stock shall result in a requirement for us, the selling stockholders or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.
Each person in a Relevant Member State who receives any communication in respect of, or who acquires any common stock under, the offers contemplated here in this prospectus will be deemed to have represented, warranted and agreed to and with each underwriter, the selling stockholders and us that:
• | it is a qualified investor as defined under the Prospectus Directive; and |
• | in the case of any common stock acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (i) the common stock acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than qualified investors, as that term is defined in the Prospectus Directive, or in the circumstances in which the prior consent of the representative of the underwriters has been given to the offer or resale or (ii) where common stock have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of such common stock to it is not treated under the Prospectus Directive as having been made to such persons. |
For the purposes of this representation and the provision above, the expression an “offer of common stock to the public” in relation to any common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any common stock to be offered so as to enable an investor to decide to purchase or subscribe for the common stock, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.
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United Kingdom
This prospectus has only been communicated or caused to have been communicated and will only be communicated or caused to be communicated as an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act of 2000 (the “FSMA”)) as received in connection with the issue or sale of the common stock in circumstances in which Section 21(1) of the FSMA does not apply to us. All applicable provisions of the FSMA will be complied with in respect to anything done in relation to the common stock in, from or otherwise involving the United Kingdom.
Notice to Residents of Canada
The offering of the common stock in Canada is being made on a private placement basis in reliance on exemptions from the prospectus requirements under the securities laws of each applicable Canadian province and territory where the common stock may be offered and sold, and therein may only be made with investors that are purchasing as principal and that qualify as both an “accredited investor” as such term is defined in National Instrument 45-106 Prospectus and Registration Exemptions and as a “permitted client” as such term is defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligation. Any offer and sale of the common stock in any province or territory of Canada may only be made through a dealer that is properly registered under the securities legislation of the applicable province or territory wherein the common stock is offered and/or sold or, alternatively, by a dealer that qualifies under and is relying upon an exemption from the registration requirements therein.
Any resale of the common stock by an investor resident in Canada must be made in accordance with applicable Canadian securities laws, which may require resales to be made in accordance with prospectus and registration requirements, statutory exemptions from the prospectus and registration requirements or under a discretionary exemption from the prospectus and registration requirements granted by the applicable Canadian securities regulatory authority. These resale restrictions may under certain circumstances apply to resales of the common stock outside of Canada.
Upon receipt of this document, each Canadian investor hereby confirms that it has expressly requested that all documents evidencing or relating in any way to the sale of the securities described herein (including for greater certainty any purchase confirmation or any notice) be drawn up in the English language only.Par la réception de ce document, chaque investisseur canadien confirme par les présentes qu’il a expressément exigé que tous les documents faisant foi ou se rapportant de quelque manière que ce soit à la vente des valeurs mobilières décrites aux présentes (incluant, pour plus de certitude, toute confirmation d’achat ou tout avis) soient rédigés en anglais seulement.
Notice to Prospective Investors in Switzerland
This prospectus does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations (“CO”) and the shares will not be listed on the SIX Swiss Exchange. Therefore, this prospectus may not comply with the disclosure standards of the CO and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange. Accordingly, the shares may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors, which do not subscribe to the shares with a view to distribution.
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The validity of our common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
The consolidated and combined financial statements of Centennial Resource Production, LLC and Celero Energy Company, LP as of December 31, 2013 and 2012, and for the years then ended, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
The statement of revenues and direct operating expenses of properties acquired by Centennial Resource Production, LLC for the eight-month period ended August 30, 2012, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
Estimates of our oil and natural gas reserves and related future net cash flows related to our properties as of September 30, 2014 included herein and elsewhere in the registration statement were based upon a reserve report prepared by independent petroleum engineers, Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website iswww.sec.gov.
As a result of this offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.
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F-1
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)
Centennial Resource Development, Inc. (the “Company”) is a newly formed Delaware corporation formed by Centennial Resource Production, LLC (“Centennial OpCo”) to become a holding company for Centennial OpCo, an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves primarily in the Delaware Basin of West Texas. The following unaudited pro forma consolidated and combined financial statements of the Company reflect the historical consolidated and combined results of Centennial OpCo and Celero Energy Company, LP (“Celero” and, together with Centennial OpCo, the “Predecessor”), on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on June 30, 2014, for pro forma balance sheet purposes, and January 1, 2013, for pro forma income statement purposes:
• | in the case of the unaudited consolidated and combined pro forma statements of operations data, the “Wolfbone Disposition” and the “CO2Project Disposition,” each as defined and described under “Recent and Formation Transactions—Recent Acquisitions and Dispositions” elsewhere in this prospectus; |
• | the corporate reorganization described under “Recent and Formation Transactions” elsewhere in this prospectus; |
• | the issuance of shares of common stock to the public at an assumed initial public offering price of $ per unit (the “Offering”) (the midpoint of the range set forth on the cover of the prospectus) and payment of related underwriting discounts and offering expenses; |
• | the application of the net proceeds from the sale of shares of common stock in this Offering in the manner described under “Use of Proceeds”; and |
• | in the case of the unaudited consolidated and combined pro forma statements of operations data, a provision for corporate income taxes at an estimated effective rate of %, inclusive of all U.S. federal, state and local income taxes. |
The unaudited pro forma consolidated and combined balance sheet of the Company is based on the unaudited historical consolidated and combined balance sheet of Predecessor as of June 30, 2014 and includes pro forma adjustments to give effect to the described transactions as if they had occurred on June 30, 2014.
The unaudited pro forma consolidated and combined statements of operations of the Company are based on (i) the audited historical consolidated and combined statement of operations of the Predecessor for the year ended December 31, 2013, and the unaudited historical consolidated and combined statement of operations of the Predecessor for the six months ended June 30, 2014, both having been adjusted to give effect to the described transactions as if they occurred on January 1, 2013, and (ii) the historical accounting records of the Predecessor.
The Predecessor reflects the combined results of Centennial OpCo and Celero, both of which are treated as flow-through entities for federal income tax purposes and, as such, are not subject to federal income tax. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, the financial data attributable to the Predecessor contains no provision for federal income tax. The Company is taxed as a C corporation under the Internal Revenue Code of 1986, as amended (the “Code”). Accordingly, the unaudited pro forma consolidated and combined financial statements have been prepared on the basis that the Company will be taxed as a corporation under the Code, and should be read in conjunction with “Recent and Formation Transactions—Corporate Formation Transactions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the audited historical consolidated and combined financial statements and related notes of the Predecessor, included elsewhere in this prospectus.
F-2
Table of Contents
The pro forma data presented reflects events directly attributable to the described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma consolidated and combined financial statements.
The unaudited pro forma consolidated and combined financial statements and related notes are presented for illustrative purposes only. If the Offering and other transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma consolidated and combined financial statements. The unaudited pro forma consolidated and combined financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma consolidated and combined statements of operations and should not be relied on as an indication of the future results the Company will have after the completion of the Offering and the other transactions contemplated by these unaudited pro forma consolidated and combined financial statements.
F-3
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
PRO FORMA CONSOLIDATED AND COMBINED BALANCE SHEET
JUNE 30, 2014
(Unaudited)
Predecessor Historical | Corporate Reorganization | Offering | Pro Forma | |||||||||||||||||
ASSETS | (in thousands) | |||||||||||||||||||
Current assets | ||||||||||||||||||||
Cash and cash equivalents | $ | 55,022 | $ | (a) | $ | (c) | $ | |||||||||||||
(d) | ||||||||||||||||||||
Accounts receivable, net: | ||||||||||||||||||||
Oil and natural gas | 14,772 | |||||||||||||||||||
Joint interest billings | 2,675 | |||||||||||||||||||
Related parties | 49 | |||||||||||||||||||
Prepaid expenses | 241 | |||||||||||||||||||
Inventory | 156 | |||||||||||||||||||
Other current assets | 30 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total current assets | 72,945 | |||||||||||||||||||
Oil and natural gas properties, other property and equipment | ||||||||||||||||||||
Oil and natural gas properties, successful efforts method | 485,251 | |||||||||||||||||||
Accumulated depreciation, depletion and amortization | (54,284 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total oil and natural gas properties, net | 430,967 | |||||||||||||||||||
Other property and equipment, net | 630 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total oil and natural gas properties, other property and equipment, net | 431,597 | |||||||||||||||||||
Noncurrent assets | ||||||||||||||||||||
Other noncurrent assets | 701 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total assets | $ | 505,243 | $ | $ | $ | |||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
LIABILITIES AND EQUITY | �� | |||||||||||||||||||
Current liabilities | ||||||||||||||||||||
Accounts payable and accrued expenses | $ | 66,731 | $ | $ | $ | |||||||||||||||
Accounts payable—related parties | 688 | |||||||||||||||||||
Derivative instruments | 4,131 | |||||||||||||||||||
Advances from joint owners | 967 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total current liabilities | 72,517 | |||||||||||||||||||
Noncurrent liabilities | ||||||||||||||||||||
Revolving credit facility | 75,000 | (d) | ||||||||||||||||||
Asset retirement obligations | 1,154 | |||||||||||||||||||
Deferred tax liability | 2,436 | (b) | ||||||||||||||||||
Derivative instruments | 1,100 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total liabilities | 152,207 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Owners’ equity | 353,036 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Common stock | — | (a) | (c) | |||||||||||||||||
Additional paid-in capital | — | (a) | (c) | |||||||||||||||||
Accumulated deficit | — | (b) | ||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total stockholders’ equity | — | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total equity | 353,036 | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Total liabilities and equity | $ | 505,243 | $ | $ | $ | |||||||||||||||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
unaudited pro forma consolidated and combined financial statements.
F-4
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
PRO FORMA CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2013
(Unaudited)
Predecessor Historical | Dispositions | Corporate Reorganization | Offering | Pro Forma | ||||||||||||||||||||
(in thousands, except per share amounts) | ||||||||||||||||||||||||
Revenues | (a | ) | ||||||||||||||||||||||
Oil sales | $ | 65,863 | $ | (20,488 | ) | $ | $ | $ | ||||||||||||||||
Natural gas and natural gas liquid sales | 4,907 | (476 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total revenues | 70,770 | (20,964 | ) | |||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Lease operating expenses | 19,193 | (13,385 | ) | |||||||||||||||||||||
Severance and ad valorem taxes | 4,153 | (1,608 | ) | |||||||||||||||||||||
Depreciation, depletion and amortization and accretion of asset retirement obligations | 29,285 | (7,591 | ) | |||||||||||||||||||||
Exploration and abandonment expenses | 8,561 | (761 | ) | |||||||||||||||||||||
General and administrative expenses | 16,842 | — | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating expenses | 78,034 | (23,345 | ) | |||||||||||||||||||||
Gain on sale of oil and natural gas properties | 16,756 | (9,174 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating income | 9,492 | (6,793 | ) | |||||||||||||||||||||
Other income (expense) | ||||||||||||||||||||||||
Interest expense | (513 | ) | — | (c) | ||||||||||||||||||||
Loss on derivative instruments | (4,410 | ) | — | |||||||||||||||||||||
Other income | 122 | 121 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total other (expense) income | (4,801 | ) | 121 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Income before income taxes | 4,691 | (6,672 | ) | |||||||||||||||||||||
Income tax expense | (1,079 | ) | — | (b) | (c) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net income | 3,612 | (6,672 | ) | |||||||||||||||||||||
Less: Loss attributable to noncontrolling interest | (6 | ) | — | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net income attributable to Predecessor | $ | 3,618 | $ | (6,672 | ) | $ | $ | $ | ||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net income per common share(d) | ||||||||||||||||||||||||
Basic and Diluted | $ | |||||||||||||||||||||||
Weighted average common shares outstanding(d) | ||||||||||||||||||||||||
Basic and Diluted |
The accompanying notes are an integral part of these
unaudited pro forma consolidated and combined financial statements.
F-5
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
PRO FORMA CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2014
(Unaudited)
Predecessor Historical | Dispositions | Corporate Reorganization | Offering | Pro Forma | ||||||||||||||||||||
(in thousands, except per share amounts) | ||||||||||||||||||||||||
Revenues | (a | ) | ||||||||||||||||||||||
Oil sales | $ | 56,295 | $ | (5,904 | ) | $ | $ | $ | ||||||||||||||||
Natural gas and natural gas liquid sales | 6,283 | (46 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total revenues | 62,578 | (5,950 | ) | |||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Lease operating expenses | 8,156 | (4,240 | ) | |||||||||||||||||||||
Severance and ad valorem taxes | 3,312 | (502 | ) | |||||||||||||||||||||
Depreciation, depletion and amortization and accretion of asset retirement obligations | 29,146 | (1,485 | ) | |||||||||||||||||||||
Exploration and abandonment expenses | 2 | (1 | ) | |||||||||||||||||||||
General and administrative expenses | 22,683 | — | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating expenses | 63,299 | (6,228 | ) | |||||||||||||||||||||
Loss on sale of oil and natural gas properties | (2,390 | ) | 2,245 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating loss | (3,111 | ) | 2,523 | |||||||||||||||||||||
Other income (expense) | ||||||||||||||||||||||||
Interest expense | (599 | ) | — | (c) | ||||||||||||||||||||
Loss on derivative instruments | (6,164 | ) | — | |||||||||||||||||||||
Other income | 239 | — | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total other expense | (6,524 | ) | — | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss before income taxes | (9, 635 | ) | 2,523 | |||||||||||||||||||||
Income tax expense | (1,027 | ) | — | (b) | (c) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net loss | (10,662 | ) | 2,523 | |||||||||||||||||||||
Less: Loss attributable to noncontrolling interest | (2 | ) | — | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net loss attributable to Predecessor | $ | (10,660 | ) | $ | 2,523 | $ | $ | $ | ||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net loss per common share(d) | $ | |||||||||||||||||||||||
Basic and Diluted | ||||||||||||||||||||||||
Weighted average common shares outstanding(d) | ||||||||||||||||||||||||
Basic and Diluted |
The accompanying notes are an integral part of these
unaudited pro forma consolidated and combined financial statements.
F-6
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
NOTE 1—BASIS OF PRESENTATION, THE OFFERING AND OTHER TRANSACTIONS
The historical financial information is derived from the consolidated and combined financial statements of Centennial Resource Production, LLC (“Centennial OpCo”) and Celero Energy, LP (“Celero” and, together with Centennial OpCo, the “Predecessor”) included elsewhere in this prospectus. For purposes of the unaudited pro forma consolidated and combined balance sheet, it is assumed that all transactions had taken place on June 30, 2014. For purposes of the unaudited pro forma consolidated and combined statements of operations, it is assumed all transactions had taken place on January 1, 2013.
Centennial OpCo (formerly known as Atlantic Energy Holdings, LLC) is an independent oil and natural gas company formed on August 30, 2012 by its management members, third party investors and NGP Natural Resources X, LP (“NGP X”), an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). In April 2014, NGP X contributed its membership interests in Centennial OpCo to Centennial Resource Development, LLC (“Centennial Holdco”), which was formed by NGP X and our current members of management. Centennial Holdco is a holding company with no independent operations apart from its ownership interests in Centennial OpCo.
Celero is an independent oil and natural gas company that was formed in 2006 by its general partner, Celero Energy Management, LLC (“Celero GP”), its management team and Natural Gas Partners VIII, L.P. (“NGP VIII”), also an affiliate of NGP.
In October 2014, Celero, Centennial OpCo, certain of their respective affiliates and certain of Celero’s former limited partners consummated substantially contemporaneously the following series of related transactions: (i) Centennial Holdco purchased for cash the Celero limited partnership units held by certain of Celero’s limited partners, (ii) Celero conveyed substantially all of its oil and natural gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo and (iii) Celero redeemed Celero limited partnership units acquired by Centennial Holdco in exchange for cash and membership interests in Centennial OpCo (the “Combination”). As a result of the Combination, Centennial Holdco owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
In connection with this Offering, all of the membership interests in Centennial OpCo, including Celero’s interest, will be contributed to Centennial Resource Development, Inc. (the “Company”), a newly formed Delaware corporation and the issuer of common stock in this offering, in exchange for shares of common stock in the Company. Generally, this transaction is expected to be tax free to the Company and each holder of Centennial OpCo membership interests, except to the extent that a holder receives cash or property other than the stock of the Company in the exchange. In general, the Company is expected to be treated for federal income tax purposes as acquiring the assets of Centennial OpCo and take a tax basis in each such asset equal to the tax basis of such asset in the hands of each person treated as transferring such asset (or a portion thereof) to the Company immediately prior to the exchange, increased by any gain recognized on the exchange by any such person. For accounting purposes, this exchange constitutes a change in tax status with respect to the Predecessor assets, requiring the Company to record a $ charge at closing against equity from continuing operations in an amount equal to the tax effect (at %, including state tax) of the excess of the carrying value of the Company’s assets for financial reporting purposes over their respective tax bases immediately after the exchange.
Upon the closing of the Offering, the Company expects to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance
F-7
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
costs, and independent director compensation. The Company estimates these direct, incremental general and administrative expenses initially will total approximately $ million per year. These direct, incremental general and administrative expenditures are not reflected in the historical consolidated and combined financial statements or in the unaudited pro forma consolidated and combined financial statements.
NOTE 2—PRO FORMA ADJUSTMENTS AND ASSUMPTIONS
The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma consolidated and combined balance sheet:
(a) | Reflects (i) the issuance of million shares of common stock to the holders of Centennial OpCo membership interests in exchange for all of their membership interest in Centennial OpCo, and (ii) the reclassification upon conversion of $ million of the Predecessor’s retained earnings to additional paid-in capital. |
(b) | Reflects estimated change in long-term deferred tax liabilities for temporary differences between the historical cost basis and tax basis of the Company’s assets and liabilities as the result of its change in tax status to a corporation. |
(c) | Reflects estimated gross proceeds of $ million from the issuance and sale of shares of common stock at an assumed initial public offering price of $ per share, net of underwriting discounts and commissions of $ million, in the aggregate, and additional estimated expenses related to the Offering of approximately $ million. |
(d) | Reflects the use of a portion of the net proceeds from the Offering to repay approximately $ million of outstanding borrowings under the Predecessor’s revolving credit facility. |
The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma consolidated and combined statement of operations:
(a) | Adjustment to reflect the reduction in revenues, expenses and other income resulting from the sale of certain oil and natural gas properties in Celero’s Wolfbone field and the CO2Project to unrelated third parties in October 2013 and May 2014, respectively, as if such sales had occurred on January 1, 2013. The adjustment applied to the historical basis of each account was based on specific identification of the assets and operations sold. |
(b) | Reflects estimated incremental income tax provision associated with the Predecessor’s historical results of operations assuming the Predecessor’s earnings had been subject to federal income tax as a corporation using a statutory tax rate of approximately %. This rate is inclusive of U.S. federal and state income taxes. |
(c) | Reflects (1) the reduction in interest expense under the Predecessor’s revolving credit facility, partially offset by an increase in unused commitment fees, as a result of the repayment of $ million of outstanding borrowings in connection with the Offering and (2) the associated income tax effect of this reduction. On a pro forma basis, there would have been no outstanding borrowings under the Predecessor’s revolving credit facility as of January 1, 2013. |
(d) | Reflects basic and diluted income (loss) per common share for the issuance and sale of shares of common stock at the initial public offering. |
F-8
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
NOTE 3—SUPPLEMENTARY DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS
The following pro forma standardized measure of the discounted net future cash flows and changes applicable to the Predecessor’s proved reserves reflect the effect of income taxes assuming Predecessor’s standardized measure had been subject to federal and state income tax as a corporation. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.
The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of Predecessor’s proved oil and natural gas properties.
The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.
The following table provides a pro forma rollforward of the total proved reserves for the year ended December 31, 2013, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year, as if all transactions reflected occurred on January 1, 2013.
Predecessor Historical | Dispositions | Pro Forma | ||||||||||
(in MBoe) | ||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||
Beginning of the year | 14,061 | (9,566 | ) | 4,495 | ||||||||
Extensions and discoveries | 6,845 | (1,858 | ) | 4,987 | ||||||||
Revisions of previous estimates | 7,350 | (6,616 | ) | 734 | ||||||||
Purchased of reserves in place | 133 | — | 133 | |||||||||
Divestitures of reserves in place | (7,323 | ) | 4,436 | (2,887 | ) | |||||||
Production | (869 | ) | 249 | (620 | ) | |||||||
|
|
|
|
|
| |||||||
End of the year | 20,197 | (13,355 | ) | 6,842 | ||||||||
|
|
|
|
|
| |||||||
Proved Developed Reserves: | ||||||||||||
Beginning of the year | 3,609 | (2,262 | ) | 1,347 | ||||||||
End of the year | 7,210 | (2,549 | ) | 4,661 | ||||||||
Proved Undeveloped Reserves: | ||||||||||||
Beginning of the year | 10,452 | (7,304 | ) | 3,148 | ||||||||
End of the year | 12,987 | (10,806 | ) | 2,181 |
F-9
Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2013:
Predecessor Historical | Dispositions | Corporate Reorganization | Pro Forma | |||||||||||||
(in thousands) | ||||||||||||||||
Future cash inflows | $ | 1,743,612 | $ | (1,237,932 | ) | $ | — | |||||||||
Future development costs | (223,227 | ) | 151,042 | — | ||||||||||||
Future production costs | (601,614 | ) | 460,370 | — | ||||||||||||
Future income tax expenses | (3,540 | ) | — | |||||||||||||
|
|
|
|
|
|
|
| |||||||||
Future net cash flows | 915,231 | (626,520 | ) | |||||||||||||
10% discount to reflect timing of cash flows | (543,924 | ) | 386,277 | |||||||||||||
|
|
|
|
|
|
|
| |||||||||
Standardized measure of discounted future net cash flows | $ | 371,307 | $ | (240,243 | ) | $ | ||||||||||
|
|
|
|
|
|
|
|
The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2013:
Predecessor Historical | Dispositions | Corporate Reorganization | Pro Forma | |||||||||||||
(in thousands) | ||||||||||||||||
Standardized measure of discounted future net cash flows at beginning of the period | $ | 257,083 | $ | (210,468 | ) | $ | — | $ | 46,615 | |||||||
Sales of oil and natural gas, net of production costs | (47,424 | ) | 6,912 | — | (40,512 | ) | ||||||||||
Purchase of minerals in place | 4,410 | — | — | 4,410 | ||||||||||||
Divestiture of minerals in place | (73,174 | ) | 56,643 | — | (16,531 | ) | ||||||||||
Extensions and discoveries, net of future development costs | 99,107 | (11,277 | ) | — | 87,830 | |||||||||||
Change in estimated development costs | 7,520 | — | — | 7,520 | ||||||||||||
Net changes in prices and production costs | 21,601 | (10,644 | ) | — | 10,957 | |||||||||||
Changes in estimated future development costs | (40,783 | ) | 17,451 | — | (23,332 | ) | ||||||||||
Revisions of previous quantity estimates | 135,759 | (122,447 | ) | — | 13,312 | |||||||||||
Accretion of discount | 19,000 | (20,094 | ) | — | (1,094 | ) | ||||||||||
Net change in income taxes | (35 | ) | — | |||||||||||||
Net changes in timing of production and other | (11,757 | ) | 53,681 | — | 41,924 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Standardized measure of discounted future net cash flows at end of the period | $ | 371,307 | $ | (240,243 | ) | $ | $ | |||||||||
|
|
|
|
|
|
|
|
F-10
Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Managers
Centennial Resource Development, Inc.:
We have audited the accompanying balance sheet of Centennial Resource Development, Inc. (the Company) as of October 31, 2014. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Centennial Resource Development, Inc. as of October 31, 2014, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Denver, CO
November 6, 2014
F-11
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
BALANCE SHEET
October 31, 2014 | ||||
TOTAL ASSETS | ||||
Cash | $ | 10 | ||
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TOTAL ASSETS | $ | 10 | ||
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STOCKHOLDER’S EQUITY | ||||
Common stock, $0.01 par value, authorized 1,000 shares; 1,000 issued and outstanding | $ | 10 | ||
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TOTAL STOCKHOLDER’S EQUITY | $ | 10 | ||
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See the accompanying notes to the balance sheet.
F-12
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO BALANCE SHEET
NOTE 1—FORMATION OF THE COMPANY AND DESCRIPTION OF BUSINESS
Centennial Resource Development, Inc. (the “Company”) was formed on October 6, 2014, pursuant to the laws of the State of Delaware to become a holding company for Centennial Resource Production, LLC.
NOTE 2—BASIS OF PRESENTATION
This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Separate statements of operations, statements of changes in stockholder’s equity and statements of cash flows have not been presented because the Company has had no business transactions or activities to date.
NOTE 3—SUBSEQUENT EVENTS
We are not aware of any events that have occurred subsequent to October 31, 2014 through the filing of Registration Statement onForm S-1 of which this prospectus is a part that would require recognition or disclosure in this financial statement.
F-13
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (Unaudited)
June 30, 2014 | December 31, 2013 | |||||||
(in thousands) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 55,022 | $ | 42,183 | ||||
Cash held in escrow | — | 5,000 | ||||||
Accounts receivable, net: | ||||||||
Oil and natural gas | 14,772 | 12,646 | ||||||
Joint interest billings | 2,675 | 2,134 | ||||||
Related parties | 49 | 433 | ||||||
Derivative instruments | — | 247 | ||||||
Prepaid expenses | 241 | 1,941 | ||||||
Inventory | 156 | 1,333 | ||||||
Other current assets | 30 | 398 | ||||||
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Total current assets | 72,945 | 66,315 | ||||||
Oil and natural gas properties, other property and equipment | ||||||||
Oil and natural gas properties, successful efforts method | 485,251 | 428,366 | ||||||
Accumulated depreciation, depletion and amortization | (54,284 | ) | (74,907 | ) | ||||
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Total oil and natural gas properties, net | 430,967 | 353,459 | ||||||
Other property and equipment, net | 630 | 4,082 | ||||||
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Total oil and natural gas properties, other property and equipment, net | 431,597 | 357,541 | ||||||
Noncurrent assets | ||||||||
Assets held for sale | — | 47,480 | ||||||
Other noncurrent assets | 701 | 749 | ||||||
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Total assets | $ | 505,243 | $ | 472,085 | ||||
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LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable and accrued expenses | $ | 66,731 | $ | 40,566 | ||||
Environmental liabilities | — | 1,011 | ||||||
Accounts payable—related parties | 688 | 128 | ||||||
Derivative instruments | 4,131 | 789 | ||||||
Advances from joint owners | 967 | 3,675 | ||||||
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Total current liabilities | 72,517 | 46,169 | ||||||
Noncurrent liabilities | ||||||||
Revolving credit facility | 75,000 | 29,000 | ||||||
Asset retirement obligations | 1,154 | 3,557 | ||||||
Deferred tax liability | 2,436 | 1,409 | ||||||
Environmental liabilities | — | 1,400 | ||||||
Derivative instruments | 1,100 | 3 | ||||||
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Total liabilities | 152,207 | 81,538 | ||||||
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Owners’ equity | 353,036 | 389,859 | ||||||
Noncontrolling interest in consolidated subsidiary | — | 688 | ||||||
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Total equity | 353,036 | 390,547 | ||||||
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Total liabilities and equity | $ | 505,243 | $ | 472,085 | ||||
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (Unaudited)
For the Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(in thousands, except per share amounts) | ||||||||
Revenues | ||||||||
Oil sales | $ | 56,295 | $ | 21,810 | ||||
Natural gas and natural gas liquid sales | 6,283 | 1,805 | ||||||
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Total revenues | 62,578 | 23,615 | ||||||
Operating expenses | ||||||||
Lease operating expenses | 8,156 | 8,489 | ||||||
Severance and ad valorem taxes | 3,312 | 1,476 | ||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,146 | 10,624 | ||||||
Exploration and abandonment expenses | 2 | 98 | ||||||
General and administrative expenses | 22,683 | 6,830 | ||||||
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Total operating expenses | 63,299 | 27,517 | ||||||
(Loss) gain on sale of oil and natural gas properties | (2,390 | ) | 1,049 | |||||
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Total operating loss | (3,111 | ) | (2,853 | ) | ||||
Other income (expense) | ||||||||
Interest expense | (599 | ) | (153 | ) | ||||
Loss on derivative instruments | (6,164 | ) | (1,184 | ) | ||||
Other income (expense) | 239 | (183 | ) | |||||
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Total other expense | (6,524 | ) | (1,520 | ) | ||||
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Loss before income taxes | (9,635 | ) | (4,373 | ) | ||||
Income tax expense | (1,027 | ) | (447 | ) | ||||
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Net loss | (10,662 | ) | (4,820 | ) | ||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | (1 | ) | ||||
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Net loss attributable to Predecessor | $ | (10,660 | ) | $ | (4,819 | ) | ||
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Pro forma information (unaudited) | ||||||||
Net loss attributable to Predecessor | $ | (10,660 | ) | |||||
Pro forma provision for income taxes | ||||||||
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Pro forma net loss | $ | |||||||
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Pro forma net loss per common share | ||||||||
Basic | $ | |||||||
Diluted | ||||||||
Weighted average pro forma common shares outstanding | ||||||||
Basic | ||||||||
Diluted |
The accompanying notes are an integral part of these
unaudited condensed consolidated and combined financial statements.
F-15
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
Total Owners’ Equity | Noncontrolling Interest in Subsidiary | Total Equity | ||||||||||
(in thousands) | ||||||||||||
Balance at December 31, 2013 | $ | 389,859 | $ | 688 | $ | 390,547 | ||||||
Contributions | 28,546 | — | 28,546 | |||||||||
Repurchase of equity interests | (87,112 | ) | — | (87,112 | ) | |||||||
Deemed contribution from sale of investment in subsidiary | 19,983 | (686 | ) | 19,297 | ||||||||
Deemed contribution from parent for payment of incentive unit compensation | 12,420 | — | 12,420 | |||||||||
Net loss | (10,660 | ) | (2 | ) | (10,662 | ) | ||||||
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Balance at June 30, 2014 | $ | 353,036 | $ | — | $ | 353,036 | ||||||
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The accompanying notes are an integral part of these
unaudited condensed consolidated and combined financial statements.
F-16
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONDENSED CONSOLIDATED AND COMBINED STATEMENT OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net loss | $ | (10,662 | ) | $ | (4,820 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Accretion of asset retirement obligations | 101 | 182 | ||||||
Depreciation, depletion and amortization | 29,045 | 10,442 | ||||||
Non-cash incentive compensation expense | 12,420 | — | ||||||
Non-cash exploration expense | 1 | 89 | ||||||
Deferred tax expense | 1,027 | 447 | ||||||
Loss (gain) on sale of oil and natural gas properties | 2,390 | (1,049 | ) | |||||
Loss on derivatives | 6,164 | 1,184 | ||||||
Net cash paid for derivative settlements | (1,478 | ) | (5,567 | ) | ||||
Payment of derivative contract premiums | — | (994 | ) | |||||
Loss on settlement of asset retirement obligations | — | 307 | ||||||
Recovery of bad debt | (777 | ) | — | |||||
Amortization of debt issuance costs | 134 | 87 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | 2,351 | 6,433 | ||||||
Prepaid and other assets | 5,024 | (154 | ) | |||||
Accounts payable | 4,533 | (5,068 | ) | |||||
Asset retirement obligation expenditures | — | (318 | ) | |||||
Other liabilities | 3,670 | 1,610 | ||||||
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Net cash provided by operating activities | 53,943 | 2,811 | ||||||
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Cash flows from investing activities: | ||||||||
Acquisition of oil and natural gas properties | (9,465 | ) | (41,678 | ) | ||||
Development of oil and natural gas properties | (140,919 | ) | (31,682 | ) | ||||
Proceeds from sales of oil and natural gas properties | 59,312 | 320 | ||||||
Purchases of other property and equipment | (75 | ) | (336 | ) | ||||
Development of assets held for sale | (14,240 | ) | (12,129 | ) | ||||
Proceeds from sale of investment in subsidiary, net of cash sold | 71,785 | — | ||||||
Change in cash held in escrow | 5,000 | 22,500 | ||||||
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Net cash used in investing activities | (28,602 | ) | (63,005 | ) | ||||
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The accompanying notes are an integral part of these
unaudited condensed consolidated and combined financial statements.
F-17
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For the Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Cash flows from financing activities: | ||||||||
Proceeds from revolving credit facility | $ | 94,000 | $ | — | ||||
Repayment of revolving credit facility | (48,000 | ) | — | |||||
Capital contributions | 28,697 | 65,217 | ||||||
Repurchase of equity interests | (87,112 | ) | — | |||||
Capital distributions | — | (21,102 | ) | |||||
Contributions received from noncontrolling interest | — | 279 | ||||||
Debt issuance costs | (87 | ) | (351 | ) | ||||
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Net cash (used in) provided by financing activities | (12,502 | ) | 44,043 | |||||
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Increase (decrease) in cash and cash equivalents | 12,839 | (16,151 | ) | |||||
Cash and cash equivalents, beginning of period | 42,183 | 46,542 | ||||||
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Cash and cash equivalents, end of period | $ | 55,022 | $ | 30,391 | ||||
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Supplemental disclosure of cash flow information: | ||||||||
Cash paid for interest | $ | 374 | $ | 23 | ||||
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Cash paid for state income tax | $ | — | $ | 300 | ||||
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Supplemental disclosure of noncash activity: | ||||||||
Changes in asset retirement obligations | $ | 117 | $ | (115 | ) | |||
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Additions to oil and natural gas properties—changes in related accruals | $ | 27,925 | $ | 1,094 | ||||
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Additions to assets held for sale—changes in related accruals | $ | — | $ | 74 | ||||
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Capital contributions—changes in related accruals | $ | — | $ | (408 | ) | |||
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Owners’ promissory note receivables | $ | — | $ | 1,990 | ||||
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The accompanying notes are an integral part of these
unaudited condensed consolidated and combined financial statements.
F-18
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC, (“Centennial OpCo”), was formed on August 30, 2012, by its management members, third-party investors and NGP Natural Resources X, LP (“NGP X”), an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware Basin of West Texas. Concurrent with the formation of Centennial OpCo, NGP X contributed $75.0 million in cash, third-party investors contributed $64.7 million in oil and natural gas properties and $0.4 million in cash, and the management members contributed $16.3 million in oil and natural gas properties to Centennial OpCo in exchange for cash and equity interests. Subsequent to the Centennial OpCo’s formation, NGP X controlled 50.5% of Centennial OpCo. During the year ended December 31, 2013, NGP X contributed an additional $115 million and, as a result, controlled 74.2% of Centennial OpCo at December 31, 2013.
On March 31, 2014, all of Centennial OpCo’s employee members sold their membership interests to Centennial OpCo. Contemporaneously, Centennial Resource Development, LLC, a Delaware limited liability company formed by NGP X and certain management members (“Centennial HoldCo”), agreed to purchase the entirety of Centennial OpCo’s issued and outstanding incentive units (see Note 10, “Incentive Compensation”). On April 30, 2014, NGP X contributed and conveyed its membership interests in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo’s remaining members sold their membership interests to Centennial OpCo. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo. Centennial HoldCo is a holding company with no independent operations apart from its ownership interests in Centennial OpCo. NGP X controls Centennial HoldCo through ownership of 99.3% of its membership interests.
Centennial OpCo owns 100% of Atlantic Exploration, LLC (“AEX”). AEX was formed on October 3, 2012, as a Delaware limited liability company and is engaged in the operation of oil and natural gas properties located primarily in the Delaware Basin, a sub-basin of the Permian Basin. Centennial OpCo also owned a 98.5% investment in Atlantic Midstream, LLC (“Atlantic Midstream”). Atlantic Midstream was formed on May 21, 2013, as a Delaware limited liability company and is constructing assets to gather and process natural gas in the Delaware Basin. Centennial OpCo sold its interests in Atlantic Midstream on February 12, 2014 (see Note 5, “Acquisitions and Divestitures”).
Celero Energy Company, LP, a Delaware limited partnership (“Celero”), was formed on September 22, 2006, by its general partner, Celero Energy Management, LLC (“Celero GP”), its management team and Natural Gas Partners VIII, L.P. (“NGP VIII”), also an affiliate of NGP. Celero is engaged in the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas.
Celero owns 100% of Celero Energy Holdings II, LLC (“Celero Holdings”) which was formed on October 12, 2006, as a Delaware limited liability company primarily to serve as the employer for Celero and to serve as the general partner of Celero Energy II, LP (“Celero II”). Celero II is a Delaware limited partnership also formed on October 12, 2006 to own and operate oil and natural gas properties primarily in New Mexico and Texas. Celero also owns 100% of Caprock Land & Cattle, LLC, a Delaware limited liability company formed on October 23, 2007 primarily to own and operate surface acreage and grazing rights in and around Celero II’s Caprock field tertiary recovery project in Chaves and Lea Counties, New Mexico. Celero sold its interests in the Caprock field in May 2014 (see Note 5, “Acquisitions and Divestitures”).
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
Celero’s Amended and Restated Agreement of Limited Partnership, dated as of October 31, 2006 (as amended to date, the “Celero LPA”) cedes control over Celero to Celero GP. Pursuant to the Celero LPA, “all management powers over the business and affairs of Celero shall be exclusively vested in Celero GP, and no Limited Partner shall have any right of control or management power over the business and affairs of Celero.” Also, pursuant to Celero LPA, NGP VIII consent is required both to dissolve the Celero and for Celero GP to withdraw as general partner. The limited partners of Celero have no approval or veto rights. NGP VIII owns 94.7% of the membership interests of Celero GP and 26.3% of the limited partnership interests in Celero.
On October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo (the “Combination”). As a result of the transaction, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Through the delegation of authority of the general partners of NGP X and NGP VIII to NGP Energy Capital Management, L.L.C. (“NGP ECM”), all power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. As all power and authority to control the core functions of Centennial OpCo and Celero (collectively, the “Predecessor”) and Centennial HoldCo are controlled by NGP X, NGP VIII, and NGP X, respectively, the Combination has been accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. The results of Centennial OpCo and Celero have been combined for all periods in which common control existed for financial reporting purposes.
All significant intercompany and intra-company balances and transactions have been eliminated. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted. We recommend that these condensed consolidated and combined financial statements be read in conjunction with our audited consolidated and combined financial statements and notes contained elsewhere in this prospectus.
In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the six month period ended June 30, 2014 are not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2014.
Assumptions, Judgments and Estimates
In the course of preparing the condensed consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.
The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.
Significant Accounting Policies
For a complete description of the Predecessor’s significant accounting policies, see Note 2, “Summary of Significant Accounting Policies,” to our annual consolidated and combined financial statements included elsewhere in this prospectus.
Accounts Receivable
As of June 30, 2014 and December 31, 2013, the Predecessor had accounts receivable, net of allowance for doubtful accounts of $17.5 million and $15.2 million, respectively. The Predecessor’s allowances for doubtful accounts were $0.4 million and $1.2 million as of June 30, 2014 and December 31, 2013. During the six months ended June 30, 2014, the Predecessor recognized a recovery of $0.8 million related to previously established allowance for doubtful accounts.
Credit Risk and Other Concentrations
The Predecessor sells oil and natural gas to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Predecessor’s control, none of which can be predicted with certainty. During the six months ended June 30, 2014, the Predecessor had one major customer, Plains Marketing, LP, which accounted for 79% of total revenue. During the six months ended June 30, 2013, the Predecessor had two major customers, Plains Marketing, LP and Oxy USA Inc., which accounted for 68% and 11%, respectively, of total revenues. The Predecessor does not believe the loss of any single purchaser would materially impact its operating results because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
At June 30, 2014, the Predecessor had derivative instruments with four counterparties. The Predecessor does not require collateral or other security from counterparties to support derivative instruments. However, to minimize the credit risk in derivative instruments, it is the Predecessor’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Predecessor uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Predecessor’s counterparties is subject to periodic review. During the six months ended June 30, 2014 and 2013, the Predecessor did not incur any losses with respect to counterparty contracts. None of the Predecessor’s existing derivative instrument contracts contains credit-risk related contingent features.
The Predecessor places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the six months ended June 30, 2014 and 2013, the Predecessor has not incurred losses related to these investments.
Fair Value of Financial Instruments
The Predecessor’s financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
instruments. The recorded value of the Predecessor’s revolving credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Predecessor had $75.0 million and $29.0 million in outstanding loans under its revolving credit facility as of June 30, 2014 and December 31, 2013, respectively. The Predecessor has derivative financial instruments that are recorded at fair value.
Income Taxes
Centennial OpCo is organized as a Delaware limited liability company and is treated as a flow-through entity for U.S. federal income tax purposes. As a result, the net taxable income of Centennial OpCo and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Celero is organized as a Delaware limited partnership and is not subject to U.S. federal or New Mexico income taxes given that such obligations are the responsibility of the partners. Accordingly, no U.S. federal tax provision has been made in the condensed consolidated and combined financial statements of the Predecessor.
The Predecessor is subject to the Texas margin tax, at a statutory rate of 1% of income. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas margin tax bases. As of June 30, 2014 and December 31, 2013, the Predecessor’s long-term deferred tax liability of $2.4 million and $1.4 million, respectively, related solely to carrying value differences associated with property and equipment for book and tax purposes.
The Predecessor evaluates the tax positions taken or expected to be taken in the course of preparing its tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Predecessor’s management does not believe that any tax positions included in its tax returns would not meet this threshold. The Predecessor’s policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.
Unaudited Pro Forma Income Taxes
These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of the Predecessor’s parent entity. In connection with the Offering, all interests in the Predecessor will be contributed to a newly formed Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended. Accordingly, a pro forma income tax provision has been disclosed as if the Predecessor was a taxable corporation for all periods presented. The Predecessor has computed pro forma tax expense using an estimated % blended corporate level U.S. federal and state tax rate.
Unaudited Pro Forma Earnings Per Share
The Predecessor has presented pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Predecessor by the number of shares of common stock attributable to the Predecessor to be issued in the initial public offering described in the registration statement, as if such shares were issued and outstanding for the six month period ended June 30, 2014.
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
NOTE 3—ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Predecessor’s asset retirement obligations for the period indicated (in thousands):
For the Six Months Ended June 30, 2014 | ||||
Asset retirement obligations, beginning of period | $ | 3,557 | ||
Liabilities incurred | 117 | |||
Liabilities disposed | (2,621 | ) | ||
Accretion expense | 101 | |||
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Asset retirement obligations, end of period | $ | 1,154 | ||
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NOTE 4—OIL AND NATURAL GAS PROPERTIES, OTHER PROPERTY AND EQUIPMENT
Oil and natural gas properties, other property and equipment includes the following for the periods indicated (in thousands):
June 30, 2014 | December 31, 2013 | |||||||
Oil and natural gas properties: | ||||||||
Proved properties | $ | 385,365 | $ | 333,368 | ||||
Unproved properties | 99,886 | 94,998 | ||||||
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Total oil and natural gas properties | 485,251 | 428,366 | ||||||
Less accumulated depreciation, depletion and amortization | (54,284 | ) | (74,907 | ) | ||||
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Oil and natural gas properties, net | 430,967 | 353,459 | ||||||
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Other property and equipment | 1,635 | 6,788 | ||||||
Less accumulated depreciation | (1,005 | ) | (2,706 | ) | ||||
|
|
|
| |||||
Other property and equipment, net | 630 | 4,082 | ||||||
|
|
|
| |||||
Oil and natural gas properties, other property and equipment, net | $ | 431,597 | $ | 357,541 | ||||
|
|
|
|
NOTE 5—ACQUISITIONS AND DIVESTITURES
In June 2014, the Predecessor acquired 2,400 net acres in the Delaware Basin from Wolverine Gas and Oil Corporation for approximately $11.0 million, of which $9.5 million had been paid at June 30, 2014.
In May 2014, the Predecessor sold its Caprock field to an unrelated third party for $59.3 million, net of normal and customary closing adjustments. A net loss of $2.2 million was recognized on the sale by the Predecessor during the second quarter of 2014. The Caprock field had a pretax net loss of $0.3 million for the six months ended June 30, 2014, excluding the loss on sale, and a pretax net loss of $2.4 million for the six months ended June 30, 2013.
F-23
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
In February 2014, the Predecessor sold its interest in Atlantic Midstream to an NGP-controlled entity for proceeds of $75.0 million. Because the Predecessor and the purchaser were under common control, the difference in proceeds and book value was recorded as an equity contribution of $20.0 million in accordance with ASC Topic 805,Business Combinations. The Atlantic Midstream assets were classified as assets held for sale in the condensed consolidated and combined balance sheets as of December 31, 2013. The historical results of operations of the Atlantic Midstream assets were not material.
NOTE 6—DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments
The Predecessor utilizes commodity derivative instruments to manage the price risk associated with forecasted sale of its crude oil production. These include over-the-counter (OTC) and exchange traded or cleared swaps, put options, and collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI). Options and collars are used to establish a floor price, or floor and ceiling prices, for expected future oil and natural gas sales. Swaps are used to lock in a fixed price for expected future oil and natural gas sales.
The following table summarizes open positions as of June 30, 2014, and represents, as of such date, derivatives in place through June 30, 2016:
2014 | 2015 | 2016 | ||||||||||
Collars: | ||||||||||||
Notional volume (Bbl) | 85,200 | — | — | |||||||||
Weighted average floor price ($/Bbl) | $ | 88.24 | $ | — | $ | — | ||||||
Weighted average ceiling price ($/Bbl) | $ | 104.15 | $ | — | $ | — | ||||||
Swaps: | ||||||||||||
Notional volume (Bbl) | 426,700 | 734,500 | 180,000 | |||||||||
Weighted average price ($/Bbl) | $ | 99.40 | $ | 92.81 | $ | 90.95 |
F-24
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
The Predecessor routinely enters into derivative contracts with a variety of counterparties, typically resulting in individual derivative instruments with both fair value asset and liability positions. The Predecessor nets the fair values of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which mitigate the credit risk of the Predecessor’s derivative instruments by providing for net settlement over the term of the contract and in the event of default or termination of the contract. The table below summarizes the gross fair value of derivative assets and liabilities and the effect of netting on the condensed consolidated and combined balance sheets (in thousands):
Balance Sheet | Gross Amounts | Netting Adjustments | Net Amounts Presented on the Balance Sheet | |||||||||||
June 30, 2014 | ||||||||||||||
Assets: | ||||||||||||||
Derivative instruments | Current assets | $ | — | $ | — | $ | — | |||||||
Derivative instruments | Non-current assets | — | — | — | ||||||||||
|
|
|
|
|
| |||||||||
Total assets | $ | — | $ | — | $ | — | ||||||||
|
|
|
|
|
| |||||||||
Liabilities: | ||||||||||||||
Derivative instruments | Current liabilities | $ | (4,131 | ) | $ | — | $ | (4,131 | ) | |||||
Derivative instruments | Non-current liabilities | (1,100 | ) | — | (1,100 | ) | ||||||||
|
|
|
|
|
| |||||||||
Total liabilities | $ | (5,231 | ) | $ | — | $ | (5,231 | ) | ||||||
|
|
|
|
|
| |||||||||
December 31, 2013 | ||||||||||||||
Assets: | ||||||||||||||
Derivative instruments | Current assets | $ | 394 | $ | (147 | ) | $ | 247 | ||||||
Derivative instruments | Non-current assets | 151 | (151 | ) | — | |||||||||
|
|
|
|
|
| |||||||||
Total assets | $ | 545 | $ | (298 | ) | $ | 247 | |||||||
|
|
|
|
|
| |||||||||
Liabilities: | ||||||||||||||
Derivative instruments | Current liabilities | $ | (936 | ) | $ | 147 | $ | (789 | ) | |||||
Derivative instruments | Non-current liabilities | (154 | ) | 151 | (3 | ) | ||||||||
|
|
|
|
|
| |||||||||
Total liabilities | $ | (1,090 | ) | $ | 298 | $ | (792 | ) | ||||||
|
|
|
|
|
|
Gains and losses from the change in fair value along with the gains or losses resulting from settlement of matured derivatives are all included inLoss on derivative instruments in the condensed consolidated and combined statements of operations. The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented (in thousands):
For the Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
Loss on derivative instruments | $ | (6,164 | ) | $ | (1,184 | ) |
F-25
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
NOTE 7—FAIR VALUE MEASUREMENTS
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Predecessor follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
• | Level 1—quoted prices in active markets for identical assets or liabilities |
• | Level 2—quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable |
• | Level 3—significant inputs to the valuation model are unobservable |
The following table is a listing of the Predecessor’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of June 30, 2014 and December 31, 2013:
Level 1 | Level 2 | Level 3 | ||||||||||
Assets (liabilities) as of June 30, 2014: | ||||||||||||
Derivative instruments | $ | — | $ | (5,231 | ) | $ | — | |||||
Assets (liabilities) as of December 31, 2013: | ||||||||||||
Derivative instruments | $ | — | $ | (545 | ) | $ | — |
The fair value of the Predecessor’s commodity derivative instruments is determined using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
There were no transfers between Level 1, Level 2 or Level 3 during any period presented.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Predecessor’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Predecessor’s asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Predecessor’s asset retirement obligations represent a nonrecurring Level 3 measurement (see Note 3, “Asset Retirement Obligations”).
F-26
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
The Predecessor reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. No impairment expense was recognized during the six months ended June 30, 2014 and 2013.
NOTE 8—LONG-TERM DEBT
At June 30, 2014, the Predecessor had $75.0 million outstanding debt and recorded interest expense of $0.6 million for the six months ended June 30, 2014 related to its five year, $500.0 million revolving credit facility with JPMorgan Chase Bank, N.A (the “2013 Credit Agreement”). In May 2014, the borrowing base of the 2013 Credit Agreement was increased to $80.0 million.
At June 30, 2014, the Predecessor was in compliance in all material respects with all covenants and ratios set forth in its revolving credit facility, except with respect to the minimum current ratio, which is the ratio of the Predecessor’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash assets accounted for under ASC Topic 815,Derivatives and Hedging (“ASC 815”) and certain restricted cash) to the Predecessor’s consolidated current liabilities (excluding the current portion of long-term debt under the old revolving credit facility and non-cash liabilities accounted for under ASC 815), of not less than 1.0 to 1.0, for which the Predecessor received a waiver.
NOTE 9—OWNERS’ EQUITY
On March 31, 2014, all of Centennial OpCo’s employee members sold their membership interests to Centennial OpCo. The total consideration paid by Centennial OpCo to acquire such interests was $11.4 million. Contemporaneously, Centennial HoldCo agreed to purchase the entirety of Centennial OpCo’s issued and outstanding incentive units (see Note 10, “Incentive Compensation”). On May 9, 2014, Centennial OpCo’s Class B members and non-employee Class A members sold their membership interests to Centennial OpCo for $75.7 million.
Centennial OpCo’s operations are governed by the provisions of a limited liability company agreement (the “Centennial OpCo LLC Agreement”). As of June 30, 2014, Centennial HoldCo had contributed $231.0 million to Centennial OpCo and the remaining commitment was $20.4 million. As of December 31, 2013, the owners of Centennial OpCo had contributed $273.1 million to Centennial OpCo, net of owners’ promissory notes receivable, and the remaining commitment was $62.0 million. Pursuant to the Centennial OpCo LLC Agreement (and as is customary for limited liability companies), the liability of the owners is limited to their contributed capital. Net income and loss are allocated to the owners based on a hypothetical liquidation. Under the terms of the Centennial OpCo LLC Agreement, Centennial OpCo will dissolve on the earlier of December 31, 2021; the sale, disposition or termination of all or substantially all of the property owned by Centennial OpCo; or consent of the Centennial OpCo’s board of managers.
F-27
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
NOTE 10—INCENTIVE COMPENSATION
Centennial OpCo Incentive Units
Under the Centennial OpCo LLC Agreement, Centennial OpCo issued certain incentive units to its management and employees. As of December 31, 2013, 850,250 of Tier I, 850,250 of Tier II, 843,990 of Tier III, 848,349 of Tier IV and 848,349 of Tier V incentive units had been issued. During the first quarter of 2014, an additional 15,909 Tier I and 15,909 Tier II of Centennial OpCo’s incentive units were issued to certain employees, resulting in 866,159 of each Tier I and Tier II incentive units outstanding as of June 30, 2014. All of the incentive units are non-voting and subject to certain vesting and performance conditions. The incentive units were accounted for as liability awards under ASC Topic 718,Compensation-Stock Compensation (“ASC 718”) with compensation expense based on period-end fair value.
On March 31, 2014, Centennial HoldCo agreed to purchase the entirety of Centennial OpCo’s issued and outstanding incentive units for total consideration of $12.4 million (the “Incentive Unit Purchase”). The closing and funding of the Incentive Unit Purchase occurred separately for each employee in accordance with each individual Membership Interest Purchase Agreement during the second and third quarters of 2014 and is included withinGeneral and administrative expense in the condensed consolidated and combined statements of operations for the six months ended June 30, 2014. Additionally, the Predecessor recorded a capital contribution from Centennial HoldCo of $12.4 million for funding of the Incentive Unit Purchase during the six months ended June 30, 2014. As a result of the Incentive Unit Purchase, all of Centennial OpCo’s incentive units were fully settled and terminated as of August 31, 2014.
Celero Incentive Units
Under the Celero LPA, Celero issued certain incentive units to its management. As of June 30, 2014 and December 31, 2013, 193,154,884 of Tier I, 64,627,250 of Tier II, 64,869,544 of Tier III and 130,223,666 of Tier IV incentive units had been issued. All of the incentive units are non-voting and subject to certain vesting and performance conditions. On May 16, 2014, all of Celero’s Tier I Incentive Units were fully vested in accordance with the Eleventh Amendment to the Celero LPA.
The incentive units are accounted for as liability awards under ASC 718 with compensation expense based on period-end fair value. No incentive compensation expense was recorded at June 30, 2014 or 2013, because it was not probable that the performance criterion would be met.
Upon completion of the Offering, Celero’s incentive units will not be liabilities of Centennial Resource Development, Inc. (the Registrant) or Centennial OpCo under ASC 718.
Centennial HoldCo Incentive Units
Under the Centennial HoldCo Limited Liability Company Agreement (the “Centennial HoldCo LLC Agreement”), Centennial HoldCo issued certain incentive units to its management and employees. As described in Note 1, on April 30, 2014, NGP X conveyed its membership interests in Centennial OpCo to Centennial HoldCo. Since that time, all of Centennial HoldCo’s employees have provided substantially all of their services to Centennial OpCo and in substance the incentive unit holders are employees of Centennial OpCo; therefore, Centennial HoldCo’s incentive units have been treated as obligations of Centennial OpCo for accounting purposes since the conveyance.
F-28
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
As of June 30, 2014 and December 31, 2013 Tier I, Tier II, Tier III, Tier IV and Tier V incentive units had been issued. The following table summarizes Centennial HoldCo’s incentive unit activity for the six months ended June 30, 2014:
Tier I | Tier II | Tier III | Tier IV | Tier V | ||||||||||||||||
Incentive units at December 31, 2013 | 655,000 | 655,000 | 655,000 | 655,000 | 655,000 | |||||||||||||||
Forfeited | — | — | — | — | — | |||||||||||||||
Granted | 50,000 | 50,000 | 50,000 | 50,000 | 50,000 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Incentive units at June 30, 2014 | 705,000 | 705,000 | 705,000 | 705,000 | 705,000 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
All of the incentive units are non-voting and subject to certain vesting and performance conditions. Tier I and II incentive units vest ratably over five years and vest in full upon the achievement of certain payout thresholds for each such Tier or upon the occurrence of a Fundamental Change, as defined in the Centennial HoldCo LLC Agreement. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such Tier. All incentive units that have not yet vested will automatically be forfeited at the time an incentive unit holder’s employment is terminated for any reason; provided, however, that prior to such forfeiture, the incentive unit holder will receive pro rata vesting based on the date of termination solely with respect to Tier I and II incentive units. Notwithstanding the foregoing, all vested and unvested incentive units will be forfeited if an incentive unit holder’s employment is terminated for “cause” (as defined in the Centennial HoldCo LLC Agreement) or if the incentive unit holder voluntarily terminates his or her employment. If an incentive unit holder’s employment is terminated other than (i) for cause or (ii) due to a voluntary termination, the incentive unit holder will retain all vested incentive units following termination. In any event, all incentive units will be forfeited on July 1, 2020 (or such earlier date upon which Centennial Holdco is dissolved pursuant to the Centennial HoldCo LLC Agreement), whether or not vested.
The incentive units are accounted for as liability awards under ASC 718 with compensation expense based on period-end fair value. No incentive compensation expense was recorded at June 30, 2014 or 2013, because it was not probable that the performance criterion would be met.
NOTE 11—TRANSACTIONS WITH RELATED PARTIES
During the six months ended June 30, 2014 and 2013, certain members of the Predecessor, their immediate family and entities affiliated or controlled by such parties owned royalty interests in certain oil and natural gas properties that the Predecessor operates. The revenues disbursed to such owners were not material in the aggregate for the six months ended June 30, 2014 or 2013.
In May 2014, Centennial OpCo became a wholly owned subsidiary of Centennial HoldCo, an NGP-controlled entity (see Note 1, “Organization and Nature of Operations”).
In February 2014, the Predecessor sold its interest in Atlantic Midstream to an NGP-controlled entity for proceeds of $75.0 million (see Note 5, “Acquisitions and Divestitures”).
In December 2012, the Predecessor received full recourse promissory notes from certain employee members under which the Predecessor would advance a cumulative amount of up to $6.6 million to the employees to meet their capital contributions. The principal balance due and accrued interest was paid in full on April 3, 2014. As of
F-29
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)—(Continued)
December 31, 2013, $5.0 million had been drawn on the promissory notes and was recorded as a reduction of members’ equity. Interest of approximately $0.1 million and $0.1 million was recorded as interest income in the condensed consolidated and combined statements of operations for the six months ended June 30, 2014 and 2013, respectively.
NOTE 12—COMMITMENTS AND CONTINGENCIES
Commitments
During 2010, the Predecessor entered into a CO2 purchase contract with Kinder Morgan CO2 Company, LP to provide CO2 for the Caprock CO2 flood project and began purchasing CO2 under the contract effective February 1, 2011. The Predecessor had a right to terminate the contract at any time by paying a termination fee, which was estimated to be $22.0 million as of December 31, 2013. In May 2014, the contract was assigned to the purchaser of the Caprock field and the Predecessor no longer has an obligation under this contract.
NOTE 13—SUBSEQUENT EVENTS
Credit Agreement
On October 15, 2014, Centennial OpCo entered into an amended and restated credit agreement (the “credit agreement”) with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65 million (the “term loan”) and a revolving credit facility (the “new revolving credit facility”) with commitments of $500 million (subject to the borrowing base), with a sublimit for letters of credit of $15 million. The term loan matures on April 15, 2017, and the new revolving credit facility matures on October 15, 2019. The amount available to be borrowed under the new revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion (and in 2015, on January 1 and July 1 as well). The credit agreement also allows, in 2016 and thereafter, for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of Centennial OpCo’s proved oil and natural gas reserves and estimated cash flows from these reserves and Centennial OpCo’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. As of October 15, 2014, the borrowing base was $145 million.
F-30
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
Report of Independent Registered Public Accounting Firm
The Board of Managers
Centennial Resource Development, Inc.:
We have audited the accompanying balance sheets of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor) as of December 31, 2013 and 2012, and the related statements of operations, changes in equity, and cash flows for each of the years in the two-year period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor) as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Denver, CO
November 6, 2014
F-31
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
CONSOLIDATED AND COMBINED BALANCE SHEETS
December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 42,183 | $ | 46,542 | ||||
Cash held in escrow | 5,000 | 34,500 | ||||||
Accounts receivable, net: | ||||||||
Oil and natural gas | 12,646 | 5,762 | ||||||
Joint interest billings | 2,134 | 7,458 | ||||||
Related parties | 433 | 606 | ||||||
Derivative instruments | 247 | 579 | ||||||
Prepaid expenses | 1,941 | 382 | ||||||
Inventory | 1,333 | 1,215 | ||||||
Other current assets | 398 | 23 | ||||||
|
|
|
| |||||
Total current assets | 66,315 | 97,067 | ||||||
Oil and natural gas properties, other property and equipment | ||||||||
Oil and natural gas properties, successful efforts method | 428,366 | 295,858 | ||||||
Accumulated depreciation, depletion and amortization | (74,907 | ) | (51,581 | ) | ||||
|
|
|
| |||||
Total oil and natural gas properties, net | 353,459 | 244,277 | ||||||
Other property and equipment, net | 4,082 | 3,926 | ||||||
|
|
|
| |||||
Total oil and natural gas properties, other property and equipment, at cost, net | 357,541 | 248,203 | ||||||
Noncurrent assets | ||||||||
Assets held for sale | 47,480 | — | ||||||
Derivative instruments | — | 700 | ||||||
Other noncurrent assets | 749 | 485 | ||||||
|
|
|
| |||||
Total assets | $ | 472,085 | $ | 346,455 | ||||
|
|
|
| |||||
LIABILITIES AND EQUITY | ||||||||
Current assets | ||||||||
Accounts payable and accrued expenses | $ | 40,566 | $ | 25,338 | ||||
Environmental liabilities | 1,011 | 919 | ||||||
Accounts payable—related parties | 128 | 528 | ||||||
Derivative instruments | 789 | 11,060 | ||||||
Asset retirement obligations | — | 262 | ||||||
Advances from joint owners | 3,675 | 4,297 | ||||||
|
|
|
| |||||
Total current liabilities | 46,169 | 42,404 | ||||||
Noncurrent liabilities | ||||||||
Revolving credit facility | 29,000 | — | ||||||
Asset retirement obligations | 3,557 | 5,053 | ||||||
Deferred tax liability | 1,409 | 330 | ||||||
Environmental liabilities | 1,400 | 1,688 | ||||||
Derivative instruments | 3 | — | ||||||
|
|
|
| |||||
Total liabilities | 81,538 | 49,475 | ||||||
|
|
|
| |||||
Owners’ equity | 389,859 | 296,980 | ||||||
Noncontrolling interest in consolidated subsidiary | 688 | — | ||||||
|
|
|
| |||||
Total equity | 390,547 | 296,980 | ||||||
|
|
|
| |||||
Total liabilities and equity | $ | 472,085 | $ | 346,455 | ||||
|
|
|
|
The accompanying notes are an integral part of these
consolidated and combined financial statements.
F-32
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
For the Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands, except per share amounts) | ||||||||
Revenues | ||||||||
Oil sales | $ | 65,863 | $ | 56,207 | ||||
Natural gas and natural gas liquid sales | 4,907 | 4,051 | ||||||
|
|
|
| |||||
Total revenues | 70,770 | 60,258 | ||||||
Operating expenses | ||||||||
Lease operating expenses | 19,193 | 22,580 | ||||||
Severance and ad valorem taxes | 4,153 | 4,275 | ||||||
Depreciation, depletion, amortization and accretion of asset retirement obligations | 29,285 | 21,035 | ||||||
Exploration and abandonment expenses | 8,561 | 10,381 | ||||||
General and administrative expenses | 16,842 | 6,939 | ||||||
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| |||||
Total operating expenses | 78,034 | 65,210 | ||||||
Gain on sale of oil and natural gas properties | 16,756 | 36,407 | ||||||
|
|
|
| |||||
Total operating income | 9,492 | 31,455 | ||||||
Other (expense) income | ||||||||
Interest expense | (513 | ) | (1,084 | ) | ||||
(Loss) gain on derivative instruments | (4,410 | ) | 2,868 | |||||
Other income (expense) | 122 | (394 | ) | |||||
|
|
|
| |||||
Total other (expense) income | (4,801 | ) | 1,390 | |||||
|
|
|
| |||||
Income before income taxes | 4,691 | 32,845 | ||||||
Income tax expense | (1,079 | ) | (563 | ) | ||||
|
|
|
| |||||
Net income | 3,612 | 32,282 | ||||||
Less: Loss attributable to noncontrolling interest | (6 | ) | — | |||||
|
|
|
| |||||
Net income attributable to Predecessor | $ | 3,618 | $ | 32,282 | ||||
|
|
|
| |||||
Pro Forma Information (Unaudited) | ||||||||
Net income attributable to predecessor | $ | 3,618 | ||||||
Pro forma provision for income taxes | ||||||||
|
| |||||||
Pro forma net income | $ | |||||||
|
| |||||||
Pro forma net income per common share | ||||||||
Basic | $ | |||||||
Diluted | $ | |||||||
Weighted average pro forma common shares outstanding | ||||||||
Basic | ||||||||
Diluted |
The accompanying notes are an integral part of these
consolidated and combined financial statements.
F-33
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY
Total Owners’ Equity | Noncontrolling Interest in Subsidiary | Total Equity | ||||||||||
(in thousands) | ||||||||||||
Balance at December 31, 2011 | $ | 105,791 | $ | — | $ | 105,791 | ||||||
Capital contributions | 180,237 | — | 180,237 | |||||||||
Capital distributions | (19,566 | ) | — | (19,566 | ) | |||||||
Owners’ promissory note receivable | (1,764 | ) | — | (1,764 | ) | |||||||
Net income | 32,282 | — | 32,282 | |||||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2012 | 296,980 | — | 296,980 | |||||||||
Capital contributions | 118,000 | 694 | 118,694 | |||||||||
Capital distributions | (25,340 | ) | — | (25,340 | ) | |||||||
Owners’ promissory note receivable | (3,399 | ) | — | (3,399 | ) | |||||||
Net income (loss) | 3,618 | (6 | ) | 3,612 | ||||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2013 | $ | 389,859 | $ | 688 | $ | 390,547 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated and combined financial statements.
F-34
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
For the Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 3,612 | $ | 32,282 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Accretion of asset retirement obligations | 358 | 187 | ||||||
Depreciation, depletion and amortization | 28,927 | 20,848 | ||||||
Non-cash exploration expense | 8,524 | 10,274 | ||||||
Deferred tax expense | 1,079 | 330 | ||||||
Gain on sale of oil and natural gas properties | (16,756 | ) | (36,407 | ) | ||||
Loss (gain) on derivative instruments | 4,410 | (2,868 | ) | |||||
Net cash paid for derivative settlements | (12,651 | ) | (12,474 | ) | ||||
Payment of derivative contract premiums | (994 | ) | (514 | ) | ||||
Provision for doubtful accounts | 1,128 | — | ||||||
Amortization of debt issuance costs | 210 | 141 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | (1,016 | ) | (8,695 | ) | ||||
Prepaid and other assets | (2,054 | ) | 204 | |||||
Accounts payable | (1,609 | ) | 11,529 | |||||
Asset retirement obligation expenditures | (369 | ) | — | |||||
Other liabilities | 617 | 5,522 | ||||||
|
|
|
| |||||
Net cash provided by operating activities | 13,416 | 20,359 | ||||||
|
|
|
| |||||
Cash flows from investing activities: | ||||||||
Acquisition of oil and natural gas properties | (27,412 | ) | (41,003 | ) | ||||
Development of oil and natural gas properties | (146,463 | ) | (82,605 | ) | ||||
Proceeds from sales of oil and natural gas properties | 46,316 | 112,260 | ||||||
Purchases of other property and equipment | (543 | ) | (547 | ) | ||||
Development of assets held for sale | (37,915 | ) | — | |||||
Change in cash held in escrow | 29,500 | (34,500 | ) | |||||
|
|
|
| |||||
Net cash used in investing activities | (136,517 | ) | (46,395 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities: | ||||||||
Proceeds from revolving credit facility | 57,000 | 50,500 | ||||||
Repayment of revolving credit facility | (28,000 | ) | (60,500 | ) | ||||
Capital contributions | 114,859 | 102,268 | ||||||
Repurchase of equity | (4,238 | ) | (19,566 | ) | ||||
Capital distributions | (21,102 | ) | — | |||||
Contributions received from noncontrolling interest | 694 | — | ||||||
Debt issuance costs | (471 | ) | (179 | ) | ||||
|
|
|
| |||||
Net cash provided by financing activities | 118,742 | 72,523 | ||||||
|
|
|
| |||||
(Decrease) increase in cash and cash equivalents | (4,359 | ) | 46,487 | |||||
Cash and cash equivalents, beginning of period | 46,542 | 55 | ||||||
|
|
|
| |||||
Cash and cash equivalents, end of period | $ | 42,183 | $ | 46,542 | ||||
|
|
|
|
The accompanying notes are an integral part of these
consolidated and combined financial statements.
F-35
Table of Contents
For the Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Supplemental disclosure of cash flow information: | ||||||||
Cash paid for interest | $ | 232 | $ | 950 | ||||
|
|
|
| |||||
Cash paid for state income taxes | $ | 253 | $ | — | ||||
|
|
|
| |||||
Supplemental disclosure of noncash activity: | ||||||||
Changes in asset retirement obligations | $ | 191 | $ | 1,280 | ||||
|
|
|
| |||||
Additions to oil and natural gas properties—changes in related accruals | $ | 5,099 | $ | 2,451 | ||||
|
|
|
| |||||
Additions to oil and natural gas properties—properties contributed | $ | — | $ | 75,798 | ||||
|
|
|
| |||||
Additions to assets held for sale—changes in related accruals | $ | 9,565 | $ | — | ||||
|
|
|
| |||||
Capital contributions—changes in related accruals | $ | (259 | ) | $ | 408 | |||
|
|
|
| |||||
Owners’ promissory note receivables | $ | 3,399 | $ | 1,764 | ||||
|
|
|
|
The accompanying notes are an integral part of these
consolidated and combined financial statements.
F-36
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC, (“Centennial OpCo”), was formed on August 30, 2012, by its management members, third-party investors and NGP Natural Resources X, LP (“NGP X”), an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware Basin of West Texas. Concurrent with the formation of Centennial OpCo, NGP X contributed $75.0 million in cash, third-party investors contributed $64.7 million in oil and natural gas properties and $0.4 million in cash, and the management members contributed $16.3 million in oil and natural gas properties to Centennial OpCo in exchange for cash and equity interests (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale”). Subsequent to the Centennial OpCo’s formation, NGP X controlled 50.5% of Centennial OpCo. During the year ended December 31, 2013, NGP X contributed an additional $115 million and, as a result, controlled 74.2% of Centennial OpCo at December 31, 2013.
Centennial OpCo owns 100% of Atlantic Exploration, LLC (“AEX”). AEX was formed on October 3, 2012, as a Delaware limited liability company and is engaged in the operation of oil and natural gas properties located primarily in the Delaware Basin of West Texas. Centennial OpCo also owned a 98.5% investment in Atlantic Midstream, LLC (“Atlantic Midstream”). Atlantic Midstream was formed on May 21, 2013, as a Delaware limited liability company and is constructing assets to gather and process natural gas in the Delaware Basin of West Texas. Centennial OpCo sold its interests in Atlantic Midstream on February 12, 2014 (see Note 12, “Subsequent Events”).
Celero Energy Company, LP (“Celero”), a Delaware limited partnership, was formed on September 22, 2006, by its general partner, Celero Energy Management, LLC (“Celero GP”), its management team and Natural Gas Partners VIII, L.P. (“NGP VIII”), also an affiliate of NGP. Celero is engaged in the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas.
Celero owns 100% of Celero Energy Holdings II, LLC (“Celero Holdings”) which was formed on October 12, 2006, as a Delaware limited liability company primarily to serve as the employer for Celero and to serve as the general partner of Celero Energy II, LP (“Celero II”). Celero II is a Delaware limited partnership also formed on October 12, 2006 to own and operate oil and natural gas properties primarily in New Mexico and Texas. Celero also owns 100% of Caprock Land & Cattle, LLC, a Delaware limited liability company formed on October 23, 2007 primarily to own and operate surface acreage and grazing rights in and around Celero II’s Caprock field tertiary recovery project in Chaves and Lea Counties, New Mexico. Celero sold its interests in the Caprock field in May 2014 (see Note 12, “Subsequent Events”).
Celero’s Amended and Restated Agreement of Limited Partnership, dated as of October 31, 2006 (as amended to date, the “Celero LPA”) cedes control over Celero to Celero GP. Pursuant to the Celero LPA, “all management powers over the business and affairs of Celero shall be exclusively vested in Celero GP, and no Limited Partner shall have any right of control or management power over the business and affairs of Celero.” Also, pursuant to Celero LPA, NGP VIII consent is required both to dissolve Celero and for Celero GP to withdraw as general partner. The limited partners of Celero have no approval or veto rights. NGP VIII owns 94.7% of the membership interests of Celero GP and 26.3% of the limited partnership interests in Celero.
On October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo (the “Combination”). As a result of
F-37
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
the transaction, Centennial Resource Development, LLC (“Centennial HoldCo”) owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Through the delegation of authority of the general partners of NGP X and NGP VIII to NGP Energy Capital Management, L.L.C. (“NGP ECM”), all power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. As all power and authority to control the core functions of Centennial OpCo and Celero (collectively, the “Predecessor”) are controlled by NGP X and NGP VIII, respectively, the Combination has been accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. The results of Centennial OpCo and Celero have been combined for all periods in which common control existed for financial reporting purposes. All significant intercompany and intra-company balances and transactions have been eliminated.
Assumptions, Judgments and Estimates
In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.
The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.
Cash and Cash Equivalents
The Predecessor considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents.
Cash Held in Escrow
Cash in escrow includes proceeds from the sale of certain oil and natural gas properties held in escrow for title examination issues and other indemnifications (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale,” under the subheading “2012 Divestitures”).
Accounts Receivable
Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Predecessor operates. For receivables from joint interest owners, the Predecessor typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months. The Predecessor establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is probable. The Predecessor’s allowance for doubtful accounts totaled $1.2 million and $0.3 million as of December 31, 2013 and 2012, respectively.
F-38
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Credit Risk and Other Concentrations
The Predecessor sells oil and natural gas to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Predecessor’s control, none of which can be predicted with certainty. During 2013, the Predecessor had one major customer, Plains Marketing, LP, which accounted for 72% of total revenue. During 2012, the Predecessor had four major customers, Genesis Crude Oil, LP, Plains Marketing, LP , Enterprise Crude Oil, and LPC Crude Oil, Inc., which accounted for 35%, 20%, 12% and 10%, respectively, of total revenues. The Predecessor does not believe the loss of any single purchaser would materially impact its operating results because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
At December 31, 2013, the Predecessor had derivative instruments with three counterparties. The Predecessor does not require collateral or other security from counterparties to support derivative instruments. However, to minimize the credit risk in derivative instruments, it is the Predecessor’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Predecessor uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Predecessor’s counterparties is subject to periodic review. During the year ended December 31, 2013 and 2012, the Predecessor did not incur any significant losses with respect to counterparty contracts. None of the Predecessor’s existing derivative instrument contracts contains credit-risk related contingent features.
The Predecessor places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the two years ended December 31, 2013, the Predecessor has not incurred losses related to these investments.
Oil and Natural Gas Properties
The Predecessor follows the successful efforts method of accounting for its oil and natural gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Geological and geophysical costs are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. As of December 31, 2013 and 2012, no costs were capitalized in connection with exploratory wells in progress.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to income.
The Predecessor carried out tertiary recovery methods on certain of its oil and natural gas properties in order to recover additional hydrocarbons that were not recoverable from primary or secondary recovery methods. Tertiary operations were conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the rules and regulations established by the Securities and Exchange Commission (the “SEC”) for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, or
F-39
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
unless the field is analogous to an existing flood. The Predecessor capitalized, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response). These capitalized development costs were included in unevaluated property costs if there are not already proved tertiary reserves in that field. Once there was a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion. During 2013, the Predecessor capitalized $2.4 million of purchased CO2 and expensed $2.4 million. During 2012, the Predecessor capitalized $5.3 million of purchased CO2 and in the fourth quarter of 2012 began expensing a portion of purchased CO2 totaling $0.2 million.
Oil and Natural Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month, first day of the month, average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and natural gas properties are depleted by field using the units-of production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Impairment of Oil and Natural Gas Properties
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Predecessor estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Predecessor will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. No impairment expense was recognized during the years ended December 31, 2013 and 2012.
Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Predecessor evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported inExploration and abandonment expenses on the combined and consolidated statements of operations. The Predecessor recorded $7.4 million and $8.6 million for impairment of unproved oil and natural gas properties for the year ended December 31, 2013 and 2012, respectively.
F-40
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Assets Held for Sale
Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the consolidated and combined balance sheets at the lower of net book value or fair value less the cost to sell (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale,” under the subheading “Assets Held for Sale”).
Other Property and Equipment
Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the consolidated balance sheet, with resulting gains or losses, if any, reflected in operations.
Fair Value of Financial Instruments
The Predecessor’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Predecessor’s credit facilities approximates their fair value as they bear interest at a floating rate that approximates a current market rate. The Predecessor had $29.0 million outstanding loans under its credit facilities as of December 31, 2013 and no borrowings outstanding under its credit facilities as of December 31, 2012. The Predecessor has derivative financial instruments that are recorded at fair value.
Asset Retirement Obligations
The Predecessor’s asset retirement obligations (“AROs”) relate to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of the ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted-risk-free rate to be used; inflation rates; and future advances in technology.
In periods subsequent to the initial measurement of the ARO, the Predecessor must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net earnings as accretion expense and is recorded inDepreciation, depletion, amortization and accretion of asset retirement obligations in the consolidated and combined statements of operations. If the liability is settled for an amount other than the recorded liability at the time of settlement, the difference is recorded inExploration and abandonment expenses in the consolidated and combined statements of operations. The Predecessor recorded $0.3 million and zero for gains on settlement of asset retirement obligations for the year ended December 31, 2013 and 2012, respectively.
F-41
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
The following table summarizes the changes in the Predecessor’s asset retirement obligations for the periods indicated (in thousands):
For the Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
Asset retirement obligations, beginning of period | $ | 5,315 | $ | 2,844 | ||||
Liabilities assumed | 83 | 1,257 | ||||||
Liabilities incurred | 308 | 37 | ||||||
Liabilities disposed | (656 | ) | (1,633 | ) | ||||
Liabilities settled | (757 | ) | (202 | ) | ||||
Accretion expense | 358 | 187 | ||||||
Revision of estimates (a) | (1,094 | ) | 2,825 | |||||
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|
|
| |||||
Asset retirement obligations, end of period | $ | 3,557 | $ | 5,315 | ||||
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|
|
|
(a) | The changes in the 2013 and 2012 estimates are primarily due to changes in the estimated useful lives of the underlying assets based on proved reserves. |
Derivative Instruments
The Predecessor utilizes commodity derivative instruments to manage the price risk associated with forecasted sale of its crude oil production. The Predecessor reports the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the accompanying consolidated and combined balance sheets. The Predecessor’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, changes in fair value are recognized in the consolidated and combined statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities.
Deferred Loan Costs
Deferred loan costs related to the Predecessor’s revolving credit facilities are included in line itemOther noncurrent assets in the consolidated and combined balance sheets and are stated at cost, net of amortization, and are amortized to interest expense on a straight line basis over the borrowing term.
Revenue Recognition
Oil and natural gas revenues are recognized when the product is sold to a purchaser, delivery has occurred, written evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonable assured. The Predecessor follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Predecessor’s share of volume sold, regardless of whether the Predecessor has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Predecessor has an imbalance on a specific property greater than the expected remaining proved reserves. The Predecessor had no significant imbalances as of December 31, 2013 or 2012.
Income Taxes
Centennial OpCo is organized as a Delaware limited liability company and is treated as a flow-through entity for U.S. federal income tax purposes. As a result, the net taxable income of Centennial OpCo and any
F-42
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.
Celero is organized as a Delaware limited partnership and is not subject to U.S. federal or New Mexico income taxes given that such obligations are the responsibility of the partners. Accordingly, no U.S. federal tax provision has been made in the consolidated and combined financial statements of the Predecessor.
The Predecessor is subject to the Texas margin tax, at a statutory rate of 1% of income. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas margin tax bases. As of December 31, 2013 and 2012, the Predecessor’s long-term deferred tax liability of $1.4 million and $0.3 million, respectively, related solely to carrying value differences associated with property, plant and equipment for book and tax purposes.
The Predecessor evaluates the tax positions taken or expected to be taken in the course of preparing its tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Predecessor’s management does not believe that any tax positions included in its tax returns would not meet this threshold. The Predecessor’s policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.
Unaudited Pro Forma Income Taxes
These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of the Predecessor’s parent entity. In connection with the Offering, all interests in the Predecessor will be contributed to a newly formed Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended. Accordingly, a pro forma income tax provision has been disclosed as if the Predecessor was a taxable corporation for all periods presented. The Predecessor has computed pro forma tax expense using a % blended corporate level U.S. federal and state tax rate.
Unaudited Pro Forma Earnings Per Share
The Predecessor has presented pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Predecessor by the number of shares of common stock attributable to the Predecessor to be issued in the initial public offering described in the registration statement, as if such shares were issued and outstanding for the period ended December 31, 2013.
Segment Reporting
The Predecessor operates in only one industry segment which is the exploration and production of oil and natural gas: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Recent Accounting Pronouncements
The accounting standard-setting organizations frequently issue new or revised accounting rules. The Predecessor regularly reviews new pronouncements to determine their impact, if any, on its consolidated and combined financial statements.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08:Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”). ASU 2014-08 changed the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Predecessor elected to early adopt ASU 2014-08 on a prospective basis. The adoption of ASU 2014-08 did not have a material impact on the consolidated and combined financial statements at December 31, 2013 or 2012.
In May 2014, the FASB issued Accounting Standard Update 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Predecessor is currently evaluating the impact, if any, of ASU 2014-09 to its consolidated and combined financial statements.
NOTE 3—OIL AND NATURAL GAS PROPERTIES, OTHER PROPERTY AND EQUIPMENT
Oil and natural gas properties, other property and equipment includes the following (in thousands):
December 31, | ||||||||
2013 | 2012 | |||||||
Oil and natural gas properties: | ||||||||
Proved properties | $ | 333,368 | $ | 184,328 | ||||
Unproved properties | 94,998 | 111,530 | ||||||
|
|
|
| |||||
Total oil and natural gas properties | 428,366 | 295,858 | ||||||
Less accumulated depreciation, depletion and amortization | (74,907 | ) | (51,581 | ) | ||||
|
|
|
| |||||
Oil and natural gas properties, net | 353,459 | 244,277 | ||||||
|
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|
| |||||
Other property and equipment | 6,788 | 6,346 | ||||||
Less accumulated depreciation | (2,706 | ) | (2,420 | ) | ||||
|
|
|
| |||||
Other property and equipment, net | 4,082 | 3,926 | ||||||
|
|
|
| |||||
Oil and natural gas properties, other property and equipment, net | $ | 357,541 | $ | 248,203 | ||||
|
|
|
|
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
NOTE 4—ACQUISITIONS, DIVESTITURES AND ASSETS HELD FOR SALE
2013 Acquisitions
During the year ended December 31, 2013, the Predecessor acquired, from third-parties, a combination of new leases and additional working interests in wells it operates through a number of separate, individually insignificant negotiated transactions for aggregate cash consideration of $20.4 million. The Predecessor reflected the total consideration paid as $4.9 million of proved oil and natural gas properties and $15.5 million of unproved oil and natural gas properties. The historical results of operations for these assets prior to and after the acquisition by the Predecessor were not material.
Additionally, the Predecessor acquired undeveloped acreage in the Wolfbone prospect for $5.9 million, of which $1.5 million was unproved acreage and $4.4 million was for proved acreage. The historical results of operations for these assets prior to and after the acquisition by the Predecessor were not material.
2012 Acquisitions
Centennial OpCo Acquisitions
As discussed in Note 1, concurrent with the formation of Centennial OpCo, third-party investors contributed $64.7 million in oil and natural gas properties and $0.4 million in cash, and management members contributed $16.3 million in oil and natural gas properties to Centennial OpCo in exchange for cash and equity interests (the “August 2012 Acquisition”). The August 2012 Acquisition was accounted for as a business combination. The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates (in thousands):
Consideration given | ||||
Cash | $ | 7,854 | ||
Equity interests | 73,593 | |||
|
| |||
Total consideration given | $ | 81,447 | ||
|
| |||
Amounts recognized for fair value of assets acquired and liabilities assumed | ||||
Proved oil and natural gas properties | $ | 13,798 | ||
Unproved oil and natural gas properties | 68,856 | |||
Asset retirement obligations | (1,207 | ) | ||
|
| |||
Total fair value of oil and gas properties acquired | $ | 81,447 | ||
|
|
Acquisition-related costs for the August 2012 Acquisition were $0.2 million for the year ended December 31, 2012, and are reflected inGeneral and administrative expenses in the consolidated and combined statements of operations. For the years ended December 31, 2013 and 2012, Centennial OpCo recorded $7.5 million and $5.3 million, respectively, in sales revenue and $3.8 million and $1.4 million, respectively, in lease operating expenses, including production and property taxes, related to the August 2012 Acquisition.
In December 2012, Centennial OpCo acquired certain oil and natural gas assets located primarily in the Delaware basin of West Texas from certain members of Centennial OpCo (the “December 2012 Acquisition”) for cash and equity interests. The acquisition was accounted for as a business combination and the purchase price
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
was primarily allocated to oil and natural gas properties. The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates (in thousands):
Consideration given | ||||
Cash | $ | 8,749 | ||
Equity interests | 2,205 | |||
|
| |||
Total consideration given | $ | 10,954 | ||
|
| |||
Amounts recognized for fair value of assets acquired and liabilities assumed | ||||
Proved oil and natural gas properties | $ | 695 | ||
Unproved oil and natural gas properties | 10,309 | |||
Asset retirement obligations | (50 | ) | ||
|
| |||
Total fair value of oil and gas properties acquired | $ | 10,954 | ||
|
|
Acquisition-related costs for the December 2012 Acquisition were $0.1 million for the year ended December 31, 2012, and are reflected inGeneral and administrative expenses in the consolidated and combined statements of operations. For the years ended December 31, 2013 and 2012, Centennial OpCo recorded $1.1 million and $0.2 million, respectively, in sales revenue and $0.4 million and $0.03 million, respectively, in lease operating expenses, including production and property taxes, from its December 2012 Acquisition. Production activity and the related revenue and operating expenses for the December 2012 Acquisition were not significant; therefore, no pro forma financial information is included for the year ended December 31, 2012.
Other 2012 Acquisitions
During the year ended December 31, 2012, the Predecessor also acquired additional acreage in its Wolfbone prospect for $24.2 million, of which $9.6 million was unproved and $14.6 million was for additional acreage in proved areas of the field. The Predecessor incurred an additional $0.2 million on other minor acquisitions in 2012, primarily on undeveloped acreage at Caprock field. The historical results of operations for these assets prior to and after the acquisition by the Predecessor were not material.
2013 Divestitures
In June 2013, the Predecessor sold its interest in its Woody Leases, which covered 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two wells, for total proceeds of $0.3 million, and realized a $0.3 million loss on sale.
In August 2013, the Predecessor sold its interest in its Windham Leases, which covered 1,951 (1,617 net) acres in Midland County, Texas, including ten wells, for total proceeds of $17.1 million and realized a $7.9 million gain on sale.
In October 2013, the Predecessor completed a sale of non-operated oil and natural gas properties in its Wolfbone prospect for total proceeds of approximately $28.7 million, and realized $7.7 million gain on sale.
2012 Divestitures
In December 2012, Celero completed a sale of oil and natural gas properties for net cash proceeds of approximately $111.9 million, including normal closing adjustments for cash revenues and costs and expenses
F-46
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
from the effective date through the date of the sale, resulting in a gain of $36.4 million in 2012. Post-closing adjustments, title defects, and other contingent post-closing items accrued as of December 31, 2012, resulted in an additional gain of $1.5 million being recognized in 2013. As of December 31, 2013 and 2012, $5.0 million and $34.5 million, respectively, of proceeds were held in escrow for title examination issues and other indemnifications. During 2013, $29.2 million was released from escrow to Celero and $0.3 million was released from escrow to the buyer. As of December 31, 2013, $5.0 million remains in the escrow account related to indemnifications that expired in March 2014 and the $5.0 million was received by Celero in April 2014. Assets included in the sale were all of Celero’s oil and natural gas properties in Texas and New Mexico, excluding its operated Caprock CO2 project in Lea and Chaves Counties, New Mexico, and its non-operated Wolfbone assets in Reeves, Ward, and Pecos Counties, Texas.
Assets Held for Sale
Assets are classified as held for sale when the Predecessor commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Subsequent changes to the estimated fair value less the costs to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value of the assets. In February 2014, the Predecessor sold its interest in Atlantic Midstream to an NGP-controlled entity. The Atlantic Midstream assets were classified as assets held for sale in the consolidated and combined balance sheets as of December 31, 2013.
NOTE 5—DERIVATIVE INSTRUMENTS
The Predecessor utilizes commodity derivative instruments to manage the price risk associated with forecasted sale of its crude oil production. These include over-the-counter (OTC) and exchange traded or cleared swaps, put options, and collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI). Options and collars are used to establish a floor price, or floor and ceiling prices, for expected future oil and natural gas sales. Swaps are used to lock in a fixed price for expected future oil and natural gas sales.
The following table summarizes open positions as of December 31, 2013, and represents, as of such date, derivatives in place through December 31, 2015:
2014 | 2015 | |||||||
Crude Oil Put Options: | ||||||||
Notional volume (Bbl) | 132,000 | — | ||||||
Weighted average price ($/Bbl) | $ | 80.00 | $ | — | ||||
Crude Oil Collars: | ||||||||
Notional volume (Bbl) | 169,500 | — | ||||||
Weighted average floor price ($/Bbl) | $ | 88.23 | $ | — | ||||
Weighted average ceiling price ($/Bbl) | $ | 104.13 | $ | — | ||||
Crude Oil Swaps: | ||||||||
Notional volume (Bbl) | 298,000 | 230,500 | ||||||
Weighted average price ($/Bbl) | $ | 93.94 | $ | 88.21 |
The Predecessor routinely enters into derivative contracts with a variety of counterparties, typically resulting in individual derivative instruments with both fair value asset and liability positions. The Predecessor nets the
F-47
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
fair values of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which mitigate the credit risk of the Predecessor’s derivative instruments by providing for net settlement over the term of the contract and in the event of default or termination of the contract. The table below summarizes the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated and combined balance sheets (in thousands):
Balance Sheet | Gross Amounts | Netting Adjustments | Net Amounts Presented on the Balance Sheet | |||||||||||
December 31, 2013 | ||||||||||||||
Assets: | ||||||||||||||
Derivative instruments | Current assets | $ | 394 | $ | (147 | ) | $ | 247 | ||||||
Derivative instruments | Non-current assets | 151 | (151 | ) | — | |||||||||
|
|
|
|
|
| |||||||||
Total assets | $ | 545 | $ | (298 | ) | $ | 247 | |||||||
|
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|
|
| |||||||||
Liabilities: | ||||||||||||||
Derivative instruments | Current liabilities | $ | (936 | ) | $ | 147 | $ | (789 | ) | |||||
Derivative instruments | Non-current liabilities | (154 | ) | 151 | (3 | ) | ||||||||
|
|
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|
|
| |||||||||
Total liabilities | $ | (1,090 | ) | $ | 298 | $ | (792 | ) | ||||||
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|
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|
|
| |||||||||
December 31, 2012: | ||||||||||||||
Assets: | ||||||||||||||
Derivative instruments | Current assets | $ | 581 | $ | (2 | ) | $ | 579 | ||||||
Derivative instruments | Non-current assets | 730 | (30 | ) | 700 | |||||||||
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|
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| |||||||||
Total assets | $ | 1,311 | $ | (32 | ) | $ | 1,279 | |||||||
|
|
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| |||||||||
Liabilities: | ||||||||||||||
Derivative instruments | Current liabilities | $ | (11,062 | ) | $ | 2 | $ | (11,060 | ) | |||||
Derivative instruments | Non-current liabilities | (30 | ) | 30 | — | |||||||||
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| |||||||||
Total liabilities | $ | (11,092 | ) | $ | 32 | $ | (11,060 | ) | ||||||
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|
|
|
|
|
Gains and losses from the change in fair value along with the gains or losses resulting from settlement of matured derivatives are all included in(Loss) gain on derivative instruments in the consolidated and combined statements of operations. The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented (in thousands):
For the Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
(Loss) gain on derivative instruments | $ | (4,410 | ) | $ | 2,868 |
NOTE 6—FAIR VALUE MEASUREMENTS
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Predecessor follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market
F-48
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
• | Level 1—quoted prices in active markets for identical assets or liabilities |
• | Level 2—quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable |
• | Level 3—significant inputs to the valuation model are unobservable |
The following table is a listing of the Predecessor’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2013 and 2012:
Level 1 | Level 2 | Level 3 | ||||||||||
Assets (liabilities) as of December 31, 2013: | ||||||||||||
Derivative instruments | $ | — | $ | (545 | ) | $ | — | |||||
Assets (liabilities) as of December 31, 2012: | ||||||||||||
Derivative instruments | $ | — | $ | (9,781 | ) | $ | — |
The fair value of the Predecessor’s commodity derivative instruments is determined using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
There were no transfers between Level 1, Level 2 or Level 3 during any period presented.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale”). Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Predecessor’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale”). Additionally, fair value is used to determine the inception value of the Predecessor’s asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Predecessor’s asset retirement obligations represent a nonrecurring Level 3 measurement (see Note 2, “Summary of Significant Account Policies,” under the subheading “Asset Retirement Obligations”).
The Predecessor reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. There were no such
F-49
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
impairments recognized during the years ended December 31, 2013 and 2012 (see Note 2, “Summary of Significant Account Policies,” under the subheading “Impairment of Oil and Natural Gas Properties”).
NOTE 7—LONG-TERM DEBT
At December 31, 2013, the Predecessor had $29.0 million outstanding debt and recorded interest expense of $0.5 million for the year ended December 31, 2013 under its revolving credit facilities described further below. At December 31, 2012, the Predecessor had zero outstanding debt and recorded interest expense of $1.0 million for the year ended December 31, 2012 under its revolving credit facilities described further below.
Centennial OpCo Credit Agreement
On June 11, 2013, Centennial OpCo entered into a 5 year, $500.0 million credit agreement with JPMorgan Chase Bank, N.A. (the “2013 Credit Agreement”) providing for a revolving line of credit with an initial borrowing base of $40.0 million. The Credit Agreement matures on June 11, 2018, and is collateralized by the oil and natural gas properties of Centennial OpCo. The borrowing base is generally subject to redetermination semiannually on April 1 and November 1 based on proved oil and natural gas reserves. There was a $0.05 million outstanding letter of credit at December 31, 2013. On November 12, 2013, the 2013 Credit Agreement was amended to increase the borrowing base to $60.0 million.
The Predecessor may elect borrowings under the Revolving Credit Facility to be either (a) Eurodollar Revolving Credit Loans (“Eurodollar”) or (b) ABR Revolving Credit loans (“ABR”). Borrowings elected as Eurodollar bear interest based on a 1-, 2-, 3-, or 6-month LIBOR Rate (“Libor”) plus an applicable margin ranging from 1.50% to 2.50%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.375% to 0.50% charged on the unutilized borrowing base amount, based upon the percentage of borrowing base unutilized. Borrowings elected as ABR bear interest at the Prime Rate (3.25% as of December 31, 2013) plus 0.50% to 1.50%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.375% to 0.50% charged on the unutilized borrowing base amount based upon the percentage of borrowing base unutilized. The Predecessor primarily utilizes Eurodollar loans. As of December 31, 2013, borrowings and letters of credit outstanding under the 2013 Credit Agreement had a weighted average interest rate of 2.09%. The Predecessor may repay any amounts borrowed prior to the maturity date without any premium or penalty.
The 2013 Credit Agreement requires the Predecessor to maintain certain financial ratios and limits the amount of indebtedness the Predecessor can incur. In addition, the credit facility includes negative covenants restricting or limiting the Predecessor’s ability to, among other things, incur additional indebtedness, consolidate or merge with other parties, pay distributions, dispose of assets, or enter into leases. More specifically, the 2013 Credit Agreement contains covenants that include:
• | a requirement that Centennial OpCo’s current assets – including amounts available to be drawn under the 2013 Credit Agreement – must exceed current liabilities; |
• | a requirement that Centennial OpCo maintain a ratio of consolidated EBITDAX to consolidated net interest expense of not less than 2.5 to 1.0; and |
• | a requirement that Centennial OpCo maintain a ratio of consolidated funded debt to consolidated EBITDAX of not more than 4.0 to 1.0 |
At December 31, 2013 the Predecessor was in compliance with its financial covenants.
F-50
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Celero Revolving Credit Facility
In August 2008, Celero entered into a $300.0 million borrowing base credit facility (“Old Revolving Credit Facility”) with BNP Paribas, as administrative agent and a group of participant banks (“Old Lenders”). The Predecessor incurred debt financing costs of $1.8 million to obtain the Old Revolving Credit Facility. These costs were being amortized over the life of the Old Revolving Credit Facility until it was paid off and the borrowing base set at zero in 2009. At that time, the unamortized debt issuance costs were charged to expense. In October 2011, Celero amended and restated the facility. The new facility amount is $100.0 million, and the borrowing base was initially set at $45.0 million, which was increased to $68.0 million in May 2012. Simultaneous with the property divestiture discussed above, the borrowing base was reduced to $21.5 million on December 21, 2012. The borrowing base was increased to $25.0 million on October 24, 2013 and remains at $25.0 million as of December 31, 2013. BNP Paribas remained as administrative agent, but Celero added a new group of participant banks (Lenders) (“Revolving Credit Facility”). The Predecessor incurred debt financing costs of $0.6 million ($0.2 million in 2012 with borrowing base increase) to obtain the Revolving Credit Facility, which are being amortized over the life of the credit facility. In May 2012, BNP Paribas sold its energy lending group to Wells Fargo Bank, N.A. (“Wells Fargo”), which became the administrative agent. On December 21, 2012, Celero also reduced the number of Lenders to Wells Fargo only, which now carries all of Celero’s Revolving Credit Facility. All amounts outstanding are due and payable in full by December 31, 2015.
The Revolving Credit Facility, which is secured by Celero’s proved oil and natural gas reserves, is subject to mandatory prepayments. The Revolving Credit Facility is at a subsidiary level, but is guaranteed by Celero Energy Company, LP and its other wholly owned subsidiaries. To the extent the borrowing base is less than the aggregate principal amount of all outstanding loans and letters of credit under the Revolving Credit Facility, the deficiency must be cured by Celero within 90 days by prepaying a portion of the outstanding amounts. Commitment fees are due quarterly and range from 0.375% to 0.500% per annum on the difference between the borrowing base amount and the average daily amount outstanding.
At the Predecessor’s option, borrowings under the Revolving Credit Facility bear interest at either (i) the “Alternate Base Rate” (i.e., the greater of the agent’s prime commercial lending rate or the federal funds rate plus 0.50% per annum plus a margin ranging from 0.75% to 1.75%) or (ii) the Eurodollar rate plus a margin ranging from 1.75% to 2.75% per annum. Both the Alternate Base Rate and the Eurodollar margins increase as the level of the Predecessor’s aggregate outstanding borrowings under the revolving credit agreement increases.
The amended and restated credit agreement contains various restrictive covenants and compliance requirements, which include (1) limiting the incurrence of additional indebtedness; (2) restrictions as to merger, sale, or transfer of assets and transactions with affiliates without the Lenders’ consent; and (3) prohibition of any return of capital payments or distributions to any of its partners other than for tax distributions. Celero must also maintain (a) a ratio of earnings before gain or loss on the disposition of assets, interest expense, depreciation, depletion and amortization expense, exploration and abandonment expenses, and other noncash charges and expenses to interest expense (Interest Coverage Ratio) of greater than 2.5 to 1.0 and (b) a positive current ratio at the end of every quarter such that current assets (excluding any derivative mark-to-market assets) plus any unused amounts under the Revolving Credit Facility exceed total current liabilities (excluding any current derivative mark-to-market liabilities).
The Revolving Credit Facility requires the Predecessor to maintain certain financial ratios and limits the amount of indebtedness the Predecessor can incur. In addition, the credit facility includes negative covenants restricting or limiting the Predecessor’s ability to, among other things, incur additional indebtedness, consolidate
F-51
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
or merge with other parties, pay distributions, dispose of assets, or enter into leases. More specifically, the 2013 Credit Agreement contains covenants that include:
• | a requirement that Celero maintain a ratio of earnings before gain or loss on the disposition of assets, interest expense, depreciation, depletion and amortization expense, exploration and abandonment expense, and other noncash charges and expenses to interest expense (Interest Coverage Ratio) of greater than 2.5 to 1.0; and |
• | a requirement that Celero maintain a positive current ratio at the end of every quarter such that current assets (excluding any derivative mark-to-market assets) plus any unused amounts under the Revolving Credit Facility exceed total current liabilities (excluding any current derivative mark-to-market liabilities). |
NOTE 8—OWNERS’ EQUITY
Centennial OpCo
Centennial OpCo’s operations are governed by the provisions of a limited liability company agreement (the “Centennial OpCo LLC Agreement”). Members include certain employees, third-party investors and NGP X. As of December 31, 2013 and 2012, the members of the Company had contributed $273.1 million and $158.5 million, respectively, to Centennial OpCo, net of members’ promissory notes receivable. As of December 31, 2013 and 2012, there were $62.0 million and $180.5 million of outstanding capital commitments of the members, respectively. Pursuant to the Centennial OpCo LLC Agreement (and as is customary for limited liability companies), the liability of the members is limited to their contributed capital. Net income and loss are allocated to the members based on a hypothetical liquidation. Under the terms of the Centennial OpCo LLC Agreement, Centennial OpCo will dissolve on the earlier of December 31, 2021; the sale, disposition or termination of all or substantially all of the property owned by Centennial OpCo; or consent of the Centennial OpCo’s board of managers.
Centennial OpCo has two classes of membership interests outstanding: Class A, which consists of interests held by NGP X, employees and third-party investors who have contributed cash to the Company; and Class B, which consists of interests held by third-party investors who have contributed oil and natural gas properties. The Class A and Class B interests are not separate legal classes of equity units and have equal rights and preferences. Distributions are made to the Class A and Class B members pro rata in accordance with their membership interests; however, once a specified level of cumulative cash distributions has been received by NGP X, the incentive unit holders receive a percentage of distributions allocable to the Class A interests based on the terms of the Centennial OpCo LLC Agreement and as discussed further below.
During the years ended December 31, 2013 and 2012, the Centennial OpCo accepted $3.4 million and $1.8 million, respectively, of capital contributions from certain employee members in exchange for full recourse promissory notes, which have been recorded as a reduction of members’ equity (see Note 10, “Transactions with Related Parties”).
Celero
Under the Celero LPA, Celero’s investment period terminated on May 31, 2012. Prior to that date, Celero made capital calls totaling $177.7 million, including a final capital call of $20.0 million called in January 2012. Celero also made tax distributions totaling $30.5 million, including a $9.4 million tax distribution in March 2011 and a $21.1 million tax distribution in March 2013. As of December 31, 2013, Celero had no remaining mandatory capital commitments from the partners.
F-52
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Under the terms of the Celero LPA, Celero will dissolve on December 31, 2014, unless extended to December 31, 2015. Partnership profits and losses are allocated based on the partners’ relative share of capital contributions pursuant to the Celero LPA as adjusted for varying levels of profitability and rate of return thresholds.
NOTE 9—INCENTIVE COMPENSATION
Centennial OpCo Incentive Units
Under the Centennial OpCo LLC Agreement, Centennial OpCo issued certain incentive units to its management and employees. In connection with the formation of Centennial OpCo in August 2012, Tier I, Tier II, Tier III and Tier IV incentive units were issued. In connection with the December 2012 Acquisition, the Centennial OpCo LLC Agreement was amended, certain of the Tier I, Tier II, Tier III and Tier IV incentive units were forfeited, and Centennial OpCo issued additional Tier I, Tier II, Tier III and Tier IV incentive units. In May 2013, the Centennial OpCo LLC Agreement was amended and the original Tier II, Tier III and Tier IV units were renamed Tier III, Tier IV and Tier V units, respectively, and new Tier II units were created and issued. The following table summarizes Centennial OpCo’s incentive unit activity for the years ended December 31, 2013 and 2012:
Tier I | Tier II | Tier III | Tier IV | Tier V | ||||||||||||||||
Incentive units granted at inception (August 30, 2012) | 614,250 | — | 614,250 | 567,000 | 567,000 | |||||||||||||||
Forfeited | (199,565 | ) | — | (199,565 | ) | (165,325 | ) | (165,325 | ) | |||||||||||
Granted | 526,567 | — | 520,319 | 537,462 | 537,462 | |||||||||||||||
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| |||||||||||
Incentive units at December 31, 2012 | 941,252 | — | 935,004 | 939,137 | 939,137 | |||||||||||||||
Forfeited | (4,557 | ) | (1,519 | ) | (4,557 | ) | — | — | ||||||||||||
Settled | (132,322 | ) | (132,322 | ) | (132,322 | ) | (136,681 | ) | (136,681 | ) | ||||||||||
Granted | 45,877 | 984,091 | 45,865 | 45,893 | 45,893 | |||||||||||||||
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| |||||||||||
Incentive units at December 31, 2013 | 850,250 | 850,250 | 843,990 | 848,349 | 848,349 | |||||||||||||||
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|
All of the incentive units are non-voting and subject to certain vesting and performance conditions. Tier I and II incentive units vest ratably over three years and vest in full upon the occurrence of a Fundamental Change, as defined in the AEH LLC Agreement. Tier I and II incentive units will be forfeited on May 16, 2018, if the payout thresholds for each such Tier are not achieved. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture on May 16, 2018, if the applicable required payouts are not achieved. In addition, all vested and unvested incentive units will be forfeited if an incentive unit holder’s employment is terminated for any reason or if the incentive unit holder voluntarily terminates their employment, unless otherwise agreed to be settled by Centennial OpCo.
The incentive units are accounted for as liability awards under ASC Topic 718,Compensation-Stock Compensation(“ASC 718”) with compensation expense based on period-end fair value. During the year ended December 31, 2013, Centennial OpCo paid $1.8 million to settle incentive units granted to certain employees who were terminated, which is included in the line itemGeneral and Administrative in the consolidated and combined statements of operations. During the year ended December 31, 2012, no payments were made in respect of the incentive units. No additional incentive compensation expense was recorded at December 31, 2013 or 2012, because it was not probable that the performance criterion would be met.
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CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Celero Incentive Units
Under the Celero LPA, Celero issued certain incentive units to its management. As of December 31, 2013 and 2012, Tier I, Tier II, Tier III and Tier IV incentive units had been issued. The following table summarizes Celero’s incentive unit activity for the years ended December 31, 2013 and 2012:
Tier I | Tier II | Tier III | Tier IV | |||||||||||||
Incentive units at December 31, 2011 | 193,154,884 | 64,627,250 | 64,869,544 | 130,223,666 | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
Granted | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Incentive units at December 31, 2012 | 193,154,884 | 64,627,250 | 64,869,544 | 130,223,666 | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
Granted | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Incentive units at December 31, 2013 | 193,154,884 | 64,627,250 | 64,869,544 | 130,223,666 | ||||||||||||
|
|
|
|
|
|
|
|
All of the incentive units are non-voting and subject to certain vesting and performance conditions. Tier I incentive units vest ratably over four years and vest in full upon the occurrence of a Fundamental Change as defined in the Celero LPA. Tier II, III, IV incentive units vest only upon the achievement of certain payout thresholds for each such Tier. Each Tier of the incentive units was subject to forfeiture on October 31, 2013 if the applicable required payouts were not achieved. The forfeiture date was extended in 2013 by the Celero’s board of managers to December 31, 2014, to correspond with the extension of the Celero partnership and it may be extended an additional ten months to October 31, 2015, by Celero’s board of managers in the future. In addition, all vested and unvested incentive units will be forfeited if an incentive unit holder’s employment is terminated without Cause (as defined in the Celero LPA) or if the incentive unit holder voluntarily terminates their employment without Good Reason (as defined in the Celero LPA).
The incentive units are accounted for as liability awards under ASC 718 with compensation expense based on period-end fair value. No incentive compensation expense was recorded at December 31, 2013 or 2012, because it was not probable that the performance criterion would be met.
Upon completion of the Offering, Celero’s incentive units will not be liabilities of Centennial Resource Development, Inc. (the Registrant) or Centennial OpCo under ASC 718.
NOTE 10—TRANSACTIONS WITH RELATED PARTIES
During the year ended December 31, 2013 and 2012, certain members of the Predecessor, their immediate family and entities affiliated or controlled by such parties owned royalty interests in certain oil and natural gas properties that the Predecessor operates. The revenues disbursed to such owners were not material in the aggregate for the year ended December 31, 2013 or 2012.
In December 2012, the Predecessor acquired certain oil and natural gas assets located primarily in the Delaware basin of West Texas from certain of its members (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale,” under the subheading “Other 2012 Acquisitions”).
In December 2012, the Predecessor received full recourse promissory notes from certain employee members under which the Predecessor would advance a cumulative amount of up to $6.6 million to the employees for capital contributions. The promissory notes are due December 31, 2021, and have a stated interest rate of
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
5.00% per annum. As of December 31, 2013 and 2012, $5.0 million and $1.8 million, respectively, had been drawn on the promissory notes and was recorded as a reduction of members’ equity. Annual interest of approximately $0.2 million and $4,000 was recorded as interest income in the consolidated and combined statements of operations for the years ended December 31, 2013 and 2012, respectively. The principal balance due and accrued interest was paid in full on April 3, 2014.
NOTE 11—COMMITMENTS AND CONTINGENCIES
General
The Predecessor is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Predecessor accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Predecessor’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Predecessor’s financial position, results of operations, or cash flows.
Legal Matters
In the ordinary course of business, the Predecessor may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Predecessor’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Predecessor requiring the reserve of a contingent liability as of the date of these consolidated and combined financial statements.
Environmental Matters
The Predecessor is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Predecessor to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites; to compensate others for damage to property and natural resources, for remediation and restoration costs, and for personal injuries; and to pay civil penalties and, in some cases, criminal penalties and punitive damages. Environmental expenditures are expensed as incurred. The Predecessor has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Predecessor accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. As of December 31, 2013 and 2012, $0.5 million of the $1.0 million and $0.9 million environmental liability, respectively, and $1.4 and $1.7 million long-term environmental liability, respectively
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
relate primarily to cleanup sites in and around the Caprock field in New Mexico. These sites were assumed in 2007 when Celero acquired the field and $4.8 million was accrued as part of the acquisition. As of December 31, 2013, $2.9 million has been spent remediating the sites. The additional $0.5 million and $0.4 million environmental liability as of December 31, 2013 and 2012, respectively, relates to an additional site identified upon selling certain properties in Texas and New Mexico (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale,” under the subheading “2012 Divestitures”). The Predecessor finalized the cleanup on this site in March 2014.
Commitments
During 2010, the Predecessor entered into a CO2 purchase contract with Kinder Morgan CO2 Company, LP to provide CO2 for the Caprock CO2 flood project. The Predecessor began purchasing CO2 under the contract effective February 1, 2011. Effective January 1, 2014, the Predecessor is contracted to purchase 46.4 Bcf of CO2 from 2014 to 2022 at a price equal to 1.75% of the monthly average NYMEX WTI price plus the then-applicable Cortez Pipeline Tariff, which is currently $0.18 per Mcf. However, the price cannot fall below a floor of $1.00 per Mcf. The Predecessor can terminate this contract at any time by paying a termination fee equal to one-fourth of the remaining contracted volumes times the then-current price. It is estimated that this termination fee as of December 31, 2013, would be approximately $22.0 million. In May 2014, the contact was assigned to the purchaser of the Caprock field and the Predecessor has no remaining obligation under this contract.
The Predecessor will owe a seller of properties acquired an additional $1.7 million if and when the net production attributed to the Caprock field exceeds 1,000 barrels of oil per day, net to the Predecessor, for 30 consecutive days.
Leases
The Predecessor has entered into operating lease agreements for office leases, corporate apartments, vehicles and equipment. The estimated future minimum lease payments under these agreements as of December 31, 2013 was as follows (in thousands):
Year Ending December 31, | ||||
2014 | $ | 1,588 | ||
2015 and thereafter | 59 | |||
|
| |||
Total | $ | 1,647 | ||
|
|
Rent expense for the year ended December 31, 2013 and 2012 was $0.8 million and $0.6 million, respectively.
NOTE 12—SUBSEQUENT EVENTS
Cash Released From Escrow
On April 8, 2014, the Predecessor received the $5.0 million held in escrow as of December 31, 2013, finalizing the sale of certain oil and natural gas properties in Texas and New Mexico (see Note 4, “Acquisitions, Divestitures and Assets Held for Sale” under the subheading “2012 Divestitures”).
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Caprock Asset Sale
In May 2014, Celero disposed of certain oil and gas properties in Chaves County, New Mexico pursuant to which Celero had pursued a tertiary recovery project utilizing CO2 to increase production on such properties (the “CO2 Project”) as described under “Recent and Formation Transactions—Recent Acquisitions and Dispositions—CO2 Project Disposition” elsewhere in this prospectus. The transaction closed on May 16, 2014, and a loss of $1.7 million was recognized.
Sale of Atlantic Midstream
On February 12, 2014, the Predecessor sold its interest in Atlantic Midstream to an NGP-controlled entity for proceeds of $75.0 million, resulting in an equity contribution of $20.0 million. The Atlantic Midstream assets are classified as assets held for sale in the consolidated and combined balance sheets as of December 31, 2013.
Incentive Units
On March 24, 2014, an additional 15,909 Tier I and 15,909 Tier II of Centennial OpCo’s Incentive Units were issued to certain employees.
Upon closing of the sale of the Caprock field noted above, on May 16, 2014, all of Celero’s Tier I Incentive Units were fully vested in accordance with the Eleventh Amendment to the Celero LPA. No incentive compensation expense was recorded because it was not probable that the performance criteria would be met at that time.
Sale of the Centennial OpCo
On March 31, 2014, all of Centennial OpCo’s employee members sold their membership interests to Centennial OpCo. The total consideration paid by Centennial OpCo to acquire such interests was $11.4 million. Contemporaneously, Centennial HoldCo agreed to purchase the entirety of Centennial OpCo’s issued and outstanding incentive units for total consideration of $12.4 million (the “Incentive Unit Purchase”). The closing and funding of the Incentive Unit Purchase will occur separately for each employee in accordance with each individual Membership Interest Purchase Agreement. On April 30, 2014, NGP X contributed and conveyed its membership interests in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo’s Class B members and remaining Class A members sold their membership interests to Centennial OpCo. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo.
Credit Agreement
On October 15, 2014, Centennial OpCo entered into an amended and restated credit agreement (the “credit agreement”) with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65 million (the “term loan”) and a revolving credit facility (the “new revolving credit facility”) with commitments of $500 million (subject to the borrowing base), with a sublimit for letters of credit of $15 million. The term loan matures in April 2017, and the new revolving credit facility matures in October 2019. The amount available to be borrowed under the new revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. The credit agreement also allows for two optional borrowing base redeterminations on January 1, 2015 and July 1, 2015. The borrowing base depends on, among other things, the volumes of Centennial OpCo’s proved oil and natural gas reserves and estimated cash flows from these reserves and Centennial OpCo’s
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless waived by the lenders. As of October 15, 2014, the borrowing base was $145 million.
NOTE 13—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED)
The Predecessor’s oil and natural gas reserves are attributable solely to properties within the United States.
Capitalized Costs
December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Oil and natural gas properties: | ||||||||
Proved properties | $ | 333,368 | $ | 184,328 | ||||
Unproved properties | 94,998 | 111,530 | ||||||
|
|
|
| |||||
Total oil and natural gas properties | 428,366 | 295,858 | ||||||
Less accumulated depreciation, depletion and amortization | (74,907 | ) | (51,581 | ) | ||||
|
|
|
| |||||
Oil and natural gas properties capitalized, net | $ | 353,459 | $ | 244,277 | ||||
|
|
|
|
Costs Incurred For Oil and Natural Gas Producing Activities
Year Ended December 31, | ||||||||
2013 | 2012 | |||||||
(in thousands) | ||||||||
Acquisition costs: | ||||||||
Proved properties | $ | 10,208 | $ | 27,872 | ||||
Unproved properties | 17,204 | 88,929 | ||||||
Development costs | 151,562 | 85,056 | ||||||
|
|
|
| |||||
Total | $ | 178,974 | $ | 201,857 | ||||
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|
|
|
Reserve Quantity Information
The following information represents the Predecessor’s estimates of its proved reserves as of December 31, 2013, which have been prepared and presented by the Predecessor’s in-house petroleum engineers in accordance with the same methodology utilized by Netherland, Sewell & Associates, Inc. in preparing our September 30, 2014 reserve report and the rules and regulations of the SEC, which require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Predecessor’s reserves as of December 31, 2013 and 2012, was based on an unweighted 12-month average West Texas Intermediate posted price per Bbl for oil and a Henry Hub spot natural gas price per Mcf for natural gas. Prices were adjusted by lease for quality, transportation fees and regional price differentials.
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Predecessor’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Permian Basin in West Texas. Moreover, the Predecessor may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Predecessor does not have any proved undeveloped reserves which have remained undeveloped for five years or more.
Estimates of the Predecessor’s proved oil and natural gas reserves at December 31, 2013 and December 31, 2012 were prepared internally by management and not by independent third party petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.
Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.
Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Predecessor emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table provides a rollforward of the total proved reserves for the years ended December 31, 2013 and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:
Year Ended December 31, 2013 | ||||||||||||
Crude Oil (MBbls) | Natural Gas and NGLs (Mcfe) | Total (MBoe) | ||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||
Beginning of the year | 11,422 | 15,836 | 14,061 | |||||||||
Extensions, discoveries and improved recovery | 12,459 | 6,990 | 13,624 | |||||||||
Revisions of previous estimates | 426 | 871 | 571 | |||||||||
Purchases of reserves in place | 109 | 142 | 133 | |||||||||
Divestitures of reserves in place | (5,193 | ) | (12,781 | ) | (7,323 | ) | ||||||
Production | (713 | ) | (933 | ) | (869 | ) | ||||||
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|
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| |||||||
End of the year | 18,510 | 10,125 | 20,197 | |||||||||
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|
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| |||||||
Proved Developed Reserves: | ||||||||||||
Beginning of the year | 2,978 | 3,788 | 3,609 | |||||||||
End of the year | 6,021 | 7,136 | 7,210 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
Beginning of the year | 8,444 | 12,048 | 10,452 | |||||||||
End of the year | 12,489 | 2,989 | 12,987 |
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Year Ended December 31, 2012 | ||||||||||||
Crude Oil (Mbls) | Natural Gas and NGLs (Mcfe) | Total (MBoe) | ||||||||||
(in thousands) | ||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||
Beginning of the year | 21,317 | 38,510 | 27,735 | |||||||||
Extensions, discoveries and improved recovery | 2,856 | 2,211 | 3,224 | |||||||||
Revisions of previous estimates | (3,418 | ) | (12,464 | ) | (5,495 | ) | ||||||
Purchases of reserves in place | 957 | 2,015 | 1,293 | |||||||||
Divestitures of reserves in place | (9,639 | ) | (13,584 | ) | (11,903 | ) | ||||||
Production | (651 | ) | (852 | ) | (793 | ) | ||||||
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|
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| |||||||
End of the year | 11,422 | 15,836 | 14,061 | |||||||||
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| |||||||
Proved Developed Reserves: | ||||||||||||
Beginning of the year | 5,221 | 7,426 | 6,459 | |||||||||
End of the year | 2,978 | 3,788 | 3,609 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
Beginning of the year | 16,096 | 31,084 | 21,276 | |||||||||
End of the year | 8,444 | 12,048 | 10,452 |
The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbls.
Extensions and discoveries were 6,845 MBoe and 1,248 MBoe during the years ended December 31, 2013 and 2012, resulting primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year.
Improved recovery resulted in additions of 6,779 MBoe and 1,976 MBoe during the years ended December 31, 2013 and 2012. Improved recovery reflects reserve additions that result from the application of tertiary recovery methods such as CO2 injection at our Caprock field. The Caprock field was sold in May 2014.
The negative revision of previously estimated quantities of 5,495 MBoe for the year ended December 31, 2012, is primarily due to a change in our development strategy to shift our focus from vertical wells to horizontal wells.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2013 and 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
December 31, | ||||||||
2013 | 2012 | |||||||
Future cash inflows | $ | 1,743,612 | $ | 1,101,695 | ||||
Future development costs | (223,227 | ) | (183,199 | ) | ||||
Future production costs | (601,614 | ) | (395,434 | ) | ||||
Future income tax expenses | (3,540 | ) | (4,720 | ) | ||||
|
|
|
| |||||
Future net cash flows(1) | 915,231 | 518,342 | ||||||
10% discount to reflect timing of cash flows | (543,924 | ) | (261,259 | ) | ||||
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|
|
| |||||
Standardized measure of discounted future net cash flows | $ | 371,307 | $ | 257,083 | ||||
|
|
|
|
(1) | Future net cash flows do not include the effects of U.S. federal income taxes on future results because Centennial OpCo is a limited liability company and Celero is a limited partnership and neither were subject to entity-level federal income taxation as of December 31, 2013 and 2012. Accordingly, no provision for federal corporate income taxes has been provided because taxable income was passed through to the Predecessor’s equity holders. The Predecessor’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. Following the Corporate Reorganization, the Predecessor will be a subchapter C corporation subject to U.S. federal and state income taxes. If the Predecessor had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 and 2012, would have been $ million and $ million, respectively. The unaudited standardized measure at December 31, 2013 and 2012 and 2011 would have been $ million and $ million, respectively. |
In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and natural gas liquids for December 31, 2013 and 2012, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Predecessor’s proved reserves. The Predecessor cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
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Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS—(Continued)
Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and natural gas liquid reserves are as follows (in thousands):
2013 | 2012 | |||||||
Standardized measure of discounted future net cash flows at beginning of the period | $ | 257,083 | $ | 395,885 | ||||
Sales of oil and natural gas, net of production costs | (47,424 | ) | (33,403 | ) | ||||
Purchase of minerals in place | 4,410 | 32,540 | ||||||
Divestiture of minerals in place | (73,174 | ) | (201,904 | ) | ||||
Extensions, discoveries and improved recovery, net of future development costs | 216,710 | 69,500 | ||||||
Change in estimated development costs | 7,520 | 29,514 | ||||||
Net changes in prices and production costs | 21,601 | (31,154 | ) | |||||
Changes in estimated future development costs | (40,783 | ) | 77,727 | |||||
Revisions of previous quantity estimates | 18,156 | (101,814 | ) | |||||
Accretion of discount | 19,000 | 20,027 | ||||||
Net change in income taxes | (35 | ) | 953 | |||||
Net changes in timing of production and other | (11,757 | ) | (788 | ) | ||||
|
|
|
| |||||
Standardized measure of discounted future net cash flows at end of the period | $ | 371,307 | $ | 257,083 | ||||
|
|
|
|
F-62
Table of Contents
The Board of Managers
Centennial Resource Production, LLC:
Report on the Financial Statements
We have audited the accompanying statement of revenues and direct operating expenses of properties acquired by Centennial Resource Production, LLC (the “Properties”) for the period from January 1, 2012 through August 30, 2012 and the related notes.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of the statements of operating revenues and direct operating expenses in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the statements of operating revenues and direct operating expense that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on this statement of operating revenue and direct operating expenses based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of operating revenues and direct operating expenses are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
We believe the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
The accompanying statement of revenues and direct operating expenses referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The statements of operating revenues and direct operating expense are not intended to be a complete presentation of the operations of the Properties.
Opinion
In our opinion, the statement of revenues and direct operating expense referred to above present fairly in all material respects, the revenues and direct operating expenses of the Properties for the period from January 1, 2012 through August 30, 2012, in accordance with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Dallas, TX
November 5, 2014
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STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY CENTENNIAL RESOURCE PRODUCTION, LLC
For the Period from January 1, 2012 through August 30, 2012 | ||||
(in thousands) | ||||
REVENUES: | ||||
Oil sales | $ | 7,483 | ||
Natural gas and natural gas liquids | 933 | |||
|
| |||
Total operating revenues | 8,416 | |||
DIRECT OPERATING EXPENSES: | ||||
Lease operating expense | 1,581 | |||
Production taxes | 72 | |||
|
| |||
Total direct operating expenses | 1,653 | |||
|
| |||
REVENUES IN EXCESS OF DIRECT OPERATING EXPENSES | $ | 6,763 | ||
|
|
See accompanying notes to the Statement of Revenues and Direct Operating Expenses of Properties Acquired by
Centennial Resource Production, LLC.
F-64
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NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY CENTENNIAL RESOURCE PRODUCTION, LLC
NOTE 1—BASIS OF PRESENTATION
On August 31, 2012, Centennial Resource Production, LLC, (the “Company”) a Delaware limited liability company, acquired (the “Acquisition”) certain oil and gas leaseholds located in the Permian Basin in West Texas (the “Acquired Properties”) from third party investors and certain of the Company’s management members (collectively the “Sellers”). The effective date for the Acquisition was July 1, 2012. The aggregate purchase price for the Acquisition was $81.4 million, including customary post-effective date adjustments, which was paid in cash and issuance of equity interests in the Company.
The accompanying Statement of Revenues and Direct Operating Expenses of the Acquired Properties by the Company (the “Statement”) was prepared by the Company based on data from the Sellers’ historical accounting records. Because the Acquired Properties are not separate legal entities, the accompanying Statement varies from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that it does not reflect certain expenses that were incurred in connection with the ownership and operation of the Acquired Properties including, but not limited to, general and administrative expenses, interest expense, and other indirect expenses. These costs were not separately allocated to the Acquired Properties in the accounting records of the Sellers. In addition, these allocations, if made using historical general and administrative structures, would not produce allocations that would be indicative of the historical performance of the Acquired Properties had they been owned by the Company due to the differing size, structure, operations and accounting policies of the Sellers and the Company. The accompanying Statement also does not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs which the Company will incur upon the allocation of the purchase price paid for the Acquired Properties. For these reasons, the Statement is not indicative of the results of operations of the Acquired Properties on a going forward basis due to changes in the business and the omission of various operating expenses. Furthermore, no balance sheet has been presented for the Acquired Properties because not all of the historical cost and related working capital balances are segregated or easily obtainable, nor has information about the Acquired Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the accompanying Statement is presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.
NOTE 2—USE OF ESTIMATES IN PREPARATION OF FINANCIAL STATEMENTS
The preparation of this Statement in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of this Statement.
NOTE 3—COMMITMENTS AND CONTINGENCIES
As represented by the Sellers in the Acquisition Agreement, there are no known claims, litigation or disputes pending as of the effective date of the Acquisition Agreement, or any matters arising in connection with indemnification, and neither the Company nor the Sellers are aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the Statement.
NOTE 4—REVENUE RECOGNITION
Seller records revenues from the sales of crude oil and natural gas when they are produced and sold. There were no gas imbalances at August 30, 2012.
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NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY CENTENNIAL RESOURCE PRODUCTION, LLC—(Continued)
NOTE 5—DIRECT OPERATING EXPENSES
Direct operating expenses are recorded when the related liability is incurred. Direct operating expenses include lease and gathering operating expenses, ad valorem taxes and production taxes. Certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Acquired Properties.
NOTE 6—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (unaudited):
Estimated quantities of proved oil and gas reserves of the Acquired Properties were derived from reserve estimates prepared by the Company’s in-house petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Acquired Properties’ proved reserves are located in the continental United States.
Guidelines prescribed in the FASB’s Accounting Standards Codification (“ASC”) Topic 932,Extractive Industries—Oil and Gas, have been followed for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus overhead incurred. Future development costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and gas reserves.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their fair value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. The standardized measure excludes income taxes as the tax basis for the Acquired Properties could not be determined or reasonably estimated for the periods presented. In addition, the tax basis of the Acquired Properties will differ from that of the Sellers so any tax provision is not relevant.
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NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY CENTENNIAL RESOURCE PRODUCTION, LLC—(Continued)
The following table sets forth information for the period from January 1, 2012 through August 30, 2012 with respect to changes in the Acquired Properties’ proved (i.e., proved developed and undeveloped) reserves:
Crude Oil (MBbls) | Natural Gas (MMcf) | MBoe | ||||||||||
January 1, 2012 | 658 | 1,186 | 856 | |||||||||
Extensions and discoveries | — | — | — | |||||||||
Revisions of previous estimates | — | — | — | |||||||||
Purchases of reserves in place | — | — | — | |||||||||
Production | (84 | ) | (157 | ) | (110 | ) | ||||||
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August 30, 2012 | 574 | 1,029 | 746 | |||||||||
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Proved Developed Reserves: | ||||||||||||
January 1, 2012 | 658 | 1,186 | 856 | |||||||||
August 30, 2012 | 574 | 1,029 | 746 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
January 1, 2012 | — | — | — | |||||||||
August 30, 2012 | — | — | — |
The following values for the crude oil and natural gas reserves at August 30, 2012, are based on prices of $94.64 per Bbl and $2.98 per Mcf. The following values for the crude oil and natural gas reserves at January 1, 2012, are based on prices of $96.19 per Bbl and $4.19 per Mcf. These prices were based on the 12 month arithmetic average of the first-day-of-the-month prices for the proceeding 12-month period. The crude oil pricing was based off the West Texas Intermediate price and natural gas pricing was based off of average Henry Hub spot natural gas prices. All prices have been adjusted for transportation, quality and basis differentials.
The following summary sets forth the Acquired Properties’ future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932:
August 30, 2012 | ||||
(in thousands) | ||||
Future cash inflows | $ | 56,165 | ||
Future development costs | — | |||
Future production costs | (24,516 | ) | ||
Future income tax expenses | — | |||
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Future net cash flows | 31,649 | |||
10% discount to reflect timing of cash flows | (12,780 | ) | ||
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Standardized measure of discounted future net cash flows | $ | 18,869 | ||
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NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF PROPERTIES ACQUIRED BY CENTENNIAL RESOURCE PRODUCTION, LLC—(Continued)
The principal sources of changes in the standardized measure of discounted future net cash flows were:
For the Period from January 1, 2012 through August 30, 2012 | ||||
(in thousands) | ||||
Standardized measure, beginning of period | $ | 23,941 | ||
Sales of oil and natural gas, net of production costs | (6,762 | ) | ||
Purchase of minerals in place | — | |||
Extensions and discoveries, net of future development costs | — | |||
Previously estimated development costs incurred during the period | — | |||
Net changes in prices and production costs | (288 | ) | ||
Changes in estimated future development costs | — | |||
Revisions of previous quantity estimates | — | |||
Accretion of discount | 1,596 | |||
Net change in income taxes | — | |||
Net changes in timing of production and other | 382 | |||
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Standardized measure, end of period | $ | 18,869 | ||
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
Analogous Reservoir. Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.
Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bbl/d. One Bbl per day.
Bcf. One billion cubic feet of natural gas.
Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Boe/d. One Boe per day.
Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
Delineation. The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development Project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Downspacing. Additional wells drilled between known producing wells to better develop the reservoir.
Dry natural gas. A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
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Economically Producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Estimated Ultimate Recovery orEUR. Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres orgross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
MBbl. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One Mcf per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.
Mcfe/d. Mcfe per day.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
Net Production. Production that is owned by us less royalties and production due to others.
Net Revenue Interest. A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.
NGLs. Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX. The New York Mercantile Exchange.
Offset operator. Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.
Oil. Oil and condensate and natural gas liquids
Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
Play. A geographic area with hydrocarbon potential.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
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Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves orPUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
Realized Price. The cash market price less all expected quality, transportation and demand adjustments.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed
Reliable Technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resources. Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
Spot Market Price. The cash market price without reduction for expected quality, transportation and demand adjustments.
Standardized measure. Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
Success Rate. The percentage of wells drilled which produce hydrocarbons in commercial quantities.
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Undeveloped acreage. Lease 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 regardless of whether such acreage contains proved reserves.
Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
Wellbore. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate.
The terms “analogous reservoir,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “proved developed reserves,” “proved reserves,” “proved undeveloped reserves,” “reliable technology,” “reserves,” and “resources” are defined by the SEC.
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Shares
Centennial Resource Development, Inc.
Common stock
Prospectus
, 2015
Barclays
Through and including , 2015(25 days after the date of this prospectus),all dealers that buy, sell or trade shares of our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
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Part II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. | Other Expenses of Issuance and Distribution |
The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.
SEC registration fee | $ | * | ||
FINRA filing fee | * | |||
NYSE listing fee | * | |||
Accounting fees and expenses | * | |||
Legal fees and expenses | * | |||
Printing and engraving expenses | * | |||
Transfer agent and registrar fees | * | |||
Miscellaneous | * | |||
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Total | $ | * | ||
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* | To be provided by amendment |
Item 14. | Indemnification of Directors and Officers |
Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.
Our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that limit the liability of our directors and officers for monetary damages to the fullest extent permitted by the DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except liability:
• | for any breach of the director’s duty of loyalty to our company or our stockholders; |
• | for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law; |
• | under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or |
• | for any transaction from which the director derived an improper personal benefit. |
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Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.
In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.
We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.
The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.
Item 15. | Recent Sales of Unregistered Securities |
Prior to the closing of this offering, based on the assumed initial public offering price of $ per share of common stock (the midpoint of the price range set forth on the cover of this prospectus), we will issue (i) shares of our common stock to the members of Centennial Resource Production, LLC in connection with our corporate reorganization. The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.
Item 16. | Exhibits and Financial Statement Schedules |
(a) Exhibits
Exhibit number | Description | |
*1.1 | Form of Underwriting Agreement | |
*3.1 | Form of Amended and Restated Certificate of Incorporation of Centennial Resource Development, Inc. | |
*3.2 | Form of Amended and Restated Bylaws of Centennial Resource Development, Inc. | |
*4.1 | Form of Common Stock Certificate | |
*4.2 | Form of Registration Rights Agreement among Centennial Resource Development, Inc., Centennial Resource Development, LLC and Celero Energy Company, LP | |
*5.1 | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered | |
10.1 | Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto |
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Exhibit number | Description | |
*10.2† | Form of Centennial Resource Development, Inc. 2015 Long-Term Incentive Plan | |
*10.3 | Form of Indemnification Agreement between Centennial Resource Development, Inc. and each of the directors and officers thereof | |
21.1 | Subsidiaries of Centennial Resource Development, Inc. | |
*23.1 | Consent of KPMG LLP | |
23.2 | Consent of Netherland, Sewell and Associates, Inc. | |
*23.3 | Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto) | |
23.4 | Consent of Nominee for Director | |
*24.1 | Power of Attorney (included on the signature page of this Registration Statement) | |
99.1 | Netherland, Sewell and Associates, Inc., Summary of Reserves at September 30, 2014 |
* | To be filed by amendment. |
† | Compensatory plan or arrangement. |
(b) Financial Statement Schedules. Financial statement schedules are omitted because the required information is not applicable, not required or included in the financial statements or the notes thereto included in the prospectus that forms a part of this registration statement.
Item 17. | Undertakings |
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
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SIGNATURES
Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on , 2014.
CENTENNIAL RESOURCE DEVELOPMENT, INC. | ||
By: | ||
Ward Polzin Chief Executive Officer |
Each person whose signature appears below appoints George Glyphyis and Jamie Wheat, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any registration statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities on , 2014.
Signature | Title | |
Ward Polzin | Chief Executive Officer and Director (Principal Executive Officer) | |
George Glyphis | Vice President and Chief Financial Officer (Principal Financial Officer) | |
Jamie Wheat | Vice President and Chief Accounting Officer (Principal Accounting Officer) | |
Roy Aneed | Director | |
David Hayes | Director |
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INDEX TO EXHIBITS
Exhibit number | Description | |
*1.1 | Form of Underwriting Agreement | |
*3.1 | Form of Amended and Restated Certificate of Incorporation of Centennial Resource Development, Inc. | |
*3.2 | Form of Amended and Restated Bylaws of Centennial Resource Development, Inc. | |
*4.1 | Form of Common Stock Certificate | |
*4.2 | Form of Registration Rights Agreement among Centennial Resource Development, Inc., Centennial Resource Development, LLC and Celero Energy Company, LP | |
*5.1 | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered | |
10.1 | Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto | |
*10.2† | Form of Centennial Resource Development, Inc. 2015 Long-Term Incentive Plan | |
*10.3 | Form of Indemnification Agreement between Centennial Resource Development, Inc. and each of the directors and officers thereof | |
21.1 | Subsidiaries of Centennial Resource Development, Inc. | |
*23.1 | Consent of KPMG LLP | |
23.2 | Consent of Netherland, Sewell and Associates, Inc. | |
*23.3 | Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto) | |
23.4 | Consent of Nominee for Director | |
*24.1 | Power of Attorney (included on the signature page of this Registration Statement) | |
99.1 | Netherland, Sewell and Associates, Inc., Summary of Reserves at September 30, 2014 |
* | To be filed by amendment. |
† | Compensatory plan or arrangement. |
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