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As filed with the Securities and Exchange Commission on February 14, 2018
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORMS-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Alta Mesa Resources, Inc.
(Exact Name of Registrant as Specified in its Charter)
Delaware (State or other jurisdiction of incorporation) | 1311 (Primary Standard Industrial Classification Code Number) | 81-4433840 (I.R.S. Employer Identification No.) |
15021 Katy Freeway, Suite 400
Houston, Texas 77094
(281)530-0991
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of registrant’s principal executive offices)
Harlan H. Chappelle
Chief Executive Officer
Alta Mesa Resources, Inc.
15021 Katy Freeway, Suite 400
Houston, Texas 77094
(281)530-0991
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)
Copies to:
Bill Nelson
Haynes and Boone, LLP
1221 McKinney, Ste 2100
Houston, Texas 77010
(713) 547-2084
Approximate date of commencement of proposed sale to the public:
From time to time 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, anon-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule12b-2 of the Exchange Act. (Check one):
Large accelerated filer | ☐ | Accelerated filer | ☐ | |||
Non-accelerated filer | ☒ (Do not check if a smaller reporting company) | Smaller reporting company | ☐ | |||
Emerging growth company | ☒ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B of the Securities Act. ☐
CALCULATION OF REGISTRATION FEE
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Title of each class of securities to be registered | Amount to be | Proposed maximum per share | Proposed maximum offering price | Amount of registration fee | ||||
Class A Common Stock, par value $0.0001 per share, underlying Public Warrants | 34,500,000(1) | $11.50(2) | $396,750,000 | $49,395.38 | ||||
Class A Common Stock, par value $0.0001 per share | 341,740,095(3) | $8.89(4) | $3,038,069,445 | $378,239.65 | ||||
TOTAL | 376,240,095 | $3,434,819,445 | $427,635.03 | |||||
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(1) | Represents the issuance by the Registrant of 34,500,000 shares of Class A Common Stock, par value $0.0001 per share, of the Registrant (the “Class A Common Stock”) underlying warrants (the “Public Warrants”) originally sold as part of units in the Registrant’s initial public offering (the “IPO”). Pursuant to Rule 416(a) under the Securities Act of 1933, as amended (the “Securities Act”), there are also being registered such indeterminable additional shares of Class A Common Stock as may be issued to prevent dilution as a result of stock splits, stock dividends or similar transactions. |
(2) | Based on the exercise price of a Public Warrant in accordance with Rule 457(g) under the Securities Act. |
(3) | Represents the resale of (i) 213,402,398 shares of Class A Common Stock that have been or may be issued by the Registrant from time to time to certain members of SRII Opco, LP, a Delaware limited partnership (“SRII Opco”), who own common units representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco, upon the redemption or exchange by such members of their SRII Opco Common Units for shares of Class A Common Stock pursuant to the limited partnership agreement of SRII Opco, (ii) the issuance of up to 59,871,031 shares of Class A Common Stock that may be issued to the contributors pursuant to those certain Contribution Agreements, dated August 16, 2017 (the “Contribution Agreements”), if theearn-out consideration described therein is issued to the contributors thereunder, (iii) the issuance of 40,000,000 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”), (iv) 15,133,333 shares of Class A Common Stock of the Registrant underlying warrants (the “Private Placements Warrants”) originally sold pursuant to that certain Private Placement Warrants Purchase Agreement, dated as of March 23, 2017 (the “Warrant Purchase Agreement”), to Silver Run Sponsor II, LLC (the “Sponsor”), and (v) 13,333,333 shares of Class A Common Stock of the Registrant underlying warrants (the “Forward Purchase Warrants”) originally sold to Fund VI Holdings pursuant to the terms of the Forward Purchase Agreement. Pursuant to Rule 416(a) under the Securities Act, there are also being registered such indeterminable additional shares of Class A Common Stock as may be issued to prevent dilution as a result of stock splits, stock dividends or similar transactions. |
(4) | Estimated at $8.89 per share, the average of the high and low prices of the Class A Common Stock as reported on The NASDAQ Capital Market on February 12, 2018, solely for the purpose of calculating the registration fee in accordance with Rule 457(f)(1) under the Securities Act. |
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 which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until the 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 contained in this prospectus is not complete and may be changed. No securities may 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 where the offer or sale is not permitted.
Subject to Completion, dated February 14, 2018
Preliminary Prospectus
ALTA MESA RESOURCES, INC.
34,500,000 Shares of Class A Common Stock Issuable upon Exercise of
Outstanding Public Warrants
341,740,095 Shares of Class A Common Stock
This prospectus relates to the issuance by Alta Mesa Resources, Inc., a Delaware corporation (the “Company,” “we,” “our” or “us”) of 34,500,000 shares of our Class A Common Stock, par value $0.0001 per share (the “Class A Common Stock”), upon the exercise of warrants (the “Public Warrants”) originally sold as part of units, consisting of one share of Class A Common Stock andone-third of one Public Warrant (the “Units”), in our initial public offering (our “IPO”). Each Public Warrant entitles the holder to purchase one share of Class A Common Stock at an exercise price of $11.50 per share. We will receive the proceeds from the exercise of the Public Warrants, but not from the sale of the underlying shares of Class A Common Stock.
This prospectus also relates to the resale of 341,740,095 shares of Class A Common Stock by the selling stockholders named in this prospectus or their permitted transferees. The shares of Class A Common Stock being offered by the selling stockholders consist of (i) 213,402,398 shares of Class A Common Stock that have been or may be issued by us from time to time to certain members of SRII Opco, LP, a Delaware limited partnership (“SRII Opco”), who own common units representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco, upon the redemption or exchange by such members of their SRII Opco Common Units for shares of Class A Common Stock pursuant to the limited partnership agreement of SRII Opco, (ii) up to 59,871,031 shares of Class A Common Stock that may be issued to the contributors pursuant to those certain Contribution Agreements, dated August 16, 2017, described herein (the “Contribution Agreements”) if theearn-out consideration described therein is issued to the contributors thereunder (the“Earn-Out Shares”), (iii) 40,000,000 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”), (iv) 15,133,333 shares of Class A Common Stock underlying warrants (the “Private Placements Warrants”) originally sold pursuant to that certain Private Placement Warrant Purchase Agreement, dated as of March 23, 2017 (the “Warrant Purchase Agreement”), to Silver Run Sponsor II, LLC (the “Sponsor”), and (v) 13,333,333 shares of Class A Common Stock underlying warrants (the “Forward Purchase Warrants”) originally sold to Fund VI Holdings pursuant to the terms of the Forward Purchase Agreement.
The selling stockholders may offer, sell or distribute all or a portion of their shares of Class A Common Stock publicly or through private transactions at prevailing market prices or at negotiated prices. Although we will receive the exercise price of the Private Placement Warrants and the Forward Purchase Warrants if those warrants are not exercised on a cashless basis, we will not receive any of the proceeds from the sale of the shares of Class A Common Stock owned by the selling stockholders. We will bear all costs, expenses and fees in connection with the registration of these shares of Class A Common Stock, including with regard to compliance with state securities or “blue sky” laws. The selling stockholders will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock. See “Plan of Distribution” beginning on page 179 of this prospectus.
The Class A Common Stock and Public Warrants are quoted on The NASDAQ Capital Market (“NASDAQ”) under the symbols “AMR” and “AMRWW,” respectively. On February 12, 2018, the closing prices of our Class A Common Stock and Public Warrants were $8.63 and $2.15, respectively. On February 12, 2018, we had 169,371,730 shares of Class A Common Stock and 34,500,000 Public Warrants issued and outstanding.
We are an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.
INVESTING IN THESE SECURITIES INVOLVES CERTAIN RISKS. SEE “RISK FACTORS” ON PAGE 10.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus is , 2018
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 101 | |||
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | 173 | |||
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TONON-U.S. HOLDERS | 192 | |||
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You should rely only on the information contained in this prospectus, any prospectus supplement or in any free writing prospectus we may authorize to be delivered or made available to you. We have not, and the selling stockholders have not, authorized anyone to provide you with different information. We and the selling stockholders are not offering to sell, or seeking offers to buy, shares of our Class A Common Stock in jurisdictions where offers and sales are not permitted. The information contained 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 shares of our Class A Common Stock.
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 nor the selling stockholders 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.
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TRADEMARKS AND TRADE NAMES
We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of 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.
GLOSSARY
Unless the context otherwise requires, references in this prospectus to:
• | “20-Day VWAP” are to the per share volume-weighted average price at which the Class A Common Stock is traded over a 20 trading day period; |
• | “Alta Mesa” are to Alta Mesa Holdings, LP, a Delaware limited partnership; |
• | “Alta Mesa Contribution Agreement” are to the Contribution Agreement, dated as of August 16, 2017, among the Alta Mesa Contributor, High Mesa GP, the sole general partner of the Alta Mesa Contributor, Alta Mesa, Alta Mesa GP, us and, solely for certain provisions therein, the equity owners of the Alta Mesa Contributor; |
• | “Alta Mesa Contributor” are to High Mesa Holdings, LP, a Delaware limited partnership; |
• | “Alta Mesa GP” are to Alta Mesa Holdings GP, LLC, a Texas limited liability company and sole general partner of Alta Mesa; |
• | “Alta Mesa Parties” are to Alta Mesa and Alta Mesa GP; |
• | “AMRI” are to Alta Mesa Resources, Inc.; |
• | “Business Combination” are to the transactions contemplated by the Contribution Agreements; |
• | “Charter” are to our Second Amended and Restated Certificate of Incorporation; |
• | “Class A Common Stock” are to our Class A Common Stock, par value $0.0001 per share; |
• | “Class B Common Stock” are to our Class B Common Stock, par value $0.0001 per share; |
• | “Class C Common Stock” are to our Class C Common Stock, par value $0.0001 per share; |
• | “Closing” are to the closing of the Business Combination; |
• | “Closing Date” are to the date on which the Closing occurred, which was February 9, 2018; |
• | “Company,” “we,” “our,” or “us” and similar terms, (i) in the context of AMRI’s E&P Business, refer to Alta Mesa prior to the Business Combination and to AMRI subsequent to the Business Combination, (ii) in the context of AMRI’s Midstream Business, refer to Kingfisher prior to the Business Combination and to AMRI subsequent to the Business Combination, and (iii) in all other contexts refers to AMRI (formerly Silver Run Acquisition Corporation II) and its subsidiaries; |
• | “Contribution Agreements” are to the Alta Mesa Contribution Agreement, the Kingfisher Contribution Agreement and the Riverstone Contribution Agreement, collectively; |
• | “Contributors” are to the Alta Mesa Contributor, the Kingfisher Contributor and the Riverstone Contributor, collectively; |
• | “Forward Purchase Agreement” are to the Forward Purchase Agreement, dated as of March 17, 2017, by and between us and Fund VI Holdings; |
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• | “founder shares” are to shares of our Class B Common Stock purchased by our Sponsor in a private placement prior to our IPO, which were converted into shares of Class A Common Stock on aone-for-one basis in connection with the Closing; |
• | “Fund VI Holdings” are to Riverstone VI SR II Holdings, L.P., a Delaware limited partnership; |
• | “High Mesa GP” are to High Mesa Holdings GP, LLC, a Texas limited liability company; |
• | “initial business combination” are to our initial merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses; |
• | “Initial Limited Partners” are to the Alta Mesa Contributor and the Riverstone Contributor; |
• | “initial stockholders” are to holders of our founder shares prior to our IPO, including our Sponsor and our independent directors prior to the Business Combination; |
• | “IPO” are to our initial public offering of units, which closed on March 29, 2017; |
• | “Kingfisher” are to Kingfisher Midstream, LLC, a Delaware limited liability company; |
• | “Kingfisher Contribution Agreement” are to the Contribution Agreement, dated as of August 16, 2017, among the Kingfisher Contributor, Kingfisher, us and, solely for certain provisions therein, the equity owners of the Kingfisher Contributor; |
• | “Kingfisher Contributor” are to KFM Holdco, LLC, a Delaware limited liability company; |
• | “management” or our “management team” are to our officers and directors; |
• | “non-STACK assets” are to assets of Alta Mesa (including the Weeks Island assets) other than its oil and gas assets located in the STACK; |
• | “Phase II assets” are to a second natural gas cryogenic processing facility, which will be located adjacent to our existing 60 MMcf/d cryogenic processing facility, with a processing capacity of 200 MMcf/d; |
• | “Preferred Stock” are to our Series A Preferred Stock and Series B Preferred Stock; |
• | “Private Placement Warrants” are to the warrants issued to the Sponsor in a private placement simultaneously with the closing of our IPO; |
• | “Private Placements” are to the issuance and sale of 40,000,000 shares of Class A Common Stock and 13,133,333 private placement warrants to Fund VI Holdings pursuant to the Forward Purchase Agreement; |
• | “public shares” are to shares of our Class A Common Stock sold as part of the units in the IPO (whether they were purchased in the IPO or thereafter in the open market); |
• | “public stockholders” are to the holders of our public shares; |
• | “Public Warrants” are to the warrants sold as part of the units in the IPO; |
• | “Riverstone” are to Riverstone Investment Group LLC and its affiliates, including our Sponsor, Fund VI Holdings and the Riverstone Contributor, collectively; |
• | “Riverstone Contribution Agreement” are to the Contribution Agreement, dated as of August 16, 2017, between the Riverstone Contributor and us; |
• | “Riverstone Contributor” are to Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership; |
• | “Series A Preferred Stock” are to our Series A Preferred Stock, par value $0.0001 per share; |
• | “Series B Preferred Stock” are to our Series B Preferred Stock, par value $0.0001 per share; |
• | “Sponsor” are to Silver Run Sponsor II, LLC, a Delaware limited liability company and an affiliate of Riverstone; |
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• | “SRII Opco” are to SRII Opco, LP, a Delaware limited partnership; |
• | “SRII Opco Common Units” are to common units representing limited partner interests in SRII Opco; |
• | “STACK” is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area; |
• | “Tax Receivable Agreement” are to the Tax Receivable Agreement entered into at Closing among us, SRII Opco and the Initial Limited Partners; |
• | “Transactions” are to (a) the consummation of the Business Combination, (b) the completion of the Private Placements and (c) the conversion of the founder shares into shares of Class A Common Stock on aone-for-one basis in connection with the Business Combination; |
• | “units” are to our units sold in our IPO, each of which consists of one share of Class A Common Stock andone-third of one Public Warrant; and |
• | “voting common stock” are to our Class A Common Stock and Class C Common Stock. |
For additional defined terms commonly used in the oil and natural gas industry and used in this prospectus, please see “Glossary of Oil and Natural Gas Terms” set forth inExhibit A.
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This summary highlights certain information appearing elsewhere in this prospectus. For a more complete understanding of this offering, you should read the entire prospectus carefully, including the risk factors and the financial statements.
Our Company
Corporate History
We were originally formed in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II for the purpose of effecting an initial business combination. On March 29, 2017, we consummated our IPO generating net proceeds of approximately $1.0 billion. Simultaneously with the closing of our IPO, we completed the private sale of 15,133,333 warrants (the “Private Placement Warrants”) to Silver Run Sponsor II, LLC (the “Sponsor”) generating gross proceeds to us of $22,700,000. A total of $1.035 billion (including approximately $36.2 million in deferred underwriting commissions to the underwriters of the IPO), which represents $1.0143 billion of the proceeds from the IPO after deducting upfront underwriting commissions of $20.7 million, and the proceeds of the sale of the private placement warrants were placed in the Trust Account (the “Trust Account”) to be used to fund an initial business combination. Until the consummation of the Business Combination, our Class A common stock, par value $0.0001 per share (the “Class A Common Stock”), warrants and units, consisting of one share of Class A Common Stock andone-third of one warrant (“units”), were traded on The NASDAQ Capital Market (“NASDAQ”) under the ticker symbols “SRUN,” “SRUNW” and “SRUNU,” respectively.
On February 9, 2018 (the “Closing Date”), we consummated the acquisition of (i) all of the limited partnership interests in Alta Mesa Holdings, LP (“Alta Mesa”), (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa Holdings GP, LLC, the sole general partner of Alta Mesa (“Alta Mesa GP”), and (iii) all of the membership interests in Kingfisher Midstream, LLC (“Kingfisher”) (such acquisition, the “Business Combination”), pursuant to:
• | the Contribution Agreement, dated as of August 16, 2017 (the “Alta Mesa Contribution Agreement”), among High Mesa Holdings, LP (the “Alta Mesa Contributor”), High Mesa Holdings GP, LLC, the sole general partner of the Alta Mesa Contributor, Alta Mesa, Alta Mesa GP, LLC, us and the equity owners of the Alta Mesa Contributor; |
• | the Contribution Agreement, dated as of August 16, 2017 (the “Kingfisher Contribution Agreement”), among KFM Holdco, LLC (the “Kingfisher Contributor”), Kingfisher, us and the equity owners of the Kingfisher Contributor; and |
• | the Contribution Agreement, dated as of August 16, 2017 (the “Riverstone Contribution Agreement” and, together with the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, the “Contribution Agreements”), between Riverstone VI Alta Mesa Holdings, L.P. (the “Riverstone Contributor” and, together with the Alta Mesa Contributor and the Kingfisher Contributor, the “Contributors”) and us. |
At the closing of the Business Combination (the “Closing”),
• | we issued 40,000,000 shares of Class A Common Stock and warrants to purchase 13,333,333 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400 million to us; |
• | we contributed $1,406 million in cash (the proceeds of the Forward Purchase Agreement and the net proceeds (after redemptions) of the Trust Account) to SRII Opco, LP, a Delaware limited partnership |
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(“SRII Opco”), in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco issued to us and (ii) 62,966,666 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”) issued to us; |
• | we caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and Kingfisher contributed to SRII Opco by the Contributors; |
• | we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to the Alta Mesa Contributor and the Kingfisher Contributor if theearn-out consideration provided for in the Contribution Agreements is earned by the Alta Mesa Contributor or the Kingfisher Contributor pursuant to the terms of the Contribution Agreements; |
• | we issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), equal to the number of the SRII Opco Common Units received by such Contributor at the Closing; |
• | SRII Opco distributed to the Kingfisher Contributor cash in the amount of approximately $814.8 million in partial payment for the ownership interests in Kingfisher contributed by the Kingfisher Contributor; and |
• | SRII Opco entered into a voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco. |
Holders of Class C Common Stock, together with holders of Class A Common Stock, voting as a single class, have the right to vote on all matters properly submitted to a vote of the stockholders, but holders of Class C Common Stock are not entitled to any dividends or liquidating distributions from us. After a specified period of time after Closing, the Contributors will generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. However, we may, at our option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.
In connection with the Closing, we also issued (i) one share of Series A Preferred Stock, par value $0.0001 per share (“Series A Preferred Stock”), to each of Bayou City Energy Management, LLC (“Bayou City”), HPS Investment Partners, LLC (“HPS”), and AM Equity Holdings, LP (“AM Management”), and (ii) one share of Series B Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), to the Riverstone Contributor. None of the holders of the Series A Preferred Stock or Series B Preferred Stock are entitled to any dividends from us related to such Preferred Stock, but such holders are entitled to preferred distributions in liquidation in the amount of $0.0001 per share of Preferred Stock, and have limited voting rights as described below. Shares of the Preferred Stock are redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Preferred Stock at the election of the holder thereof or (3) upon a breach by the holder of the transfer restrictions applicable to such Preferred Stock. For so long as the Series A Preferred Stock or Series B Preferred Stock remains outstanding, as applicable, the holders thereof will be entitled to nominate and elect directors to our board of directors for a period of up to five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock.
On February 6, 2018, our stockholders voted to approve the Business Combination. In connection with that vote, the holders of shares of Class A Common Stock originally sold as part of the units issued in our IPO (such holders, the “public stockholders”), were provided with the opportunity to redeem shares of Class A Common
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Stock then held by them for cash equal to approximately $10.00 per share. Public holders of 3,270 shares of Class A Common Stock elected to redeem those shares and, at the Closing, $32,944 held in the Trust Account was paid to such redeeming shareholders and the remaining $1,042.7 million held in the Trust Account was disbursed to us to fund our obligations under the Contribution Agreements and to pay the underwriters’ deferred discount arising out of the IPO.
Following the Business Combination, we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” and continued the listing of our Class A Common Stock and Public Warrants on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Following the completion of the Business Combination, the size of our board of directors was expanded from four directors to 11, including one director appointed by Bayou City and its affiliates, one director appointed by HPS and its affiliates and two directors appointed by AM Management and its affiliates, as the holders of our Series A Preferred Stock, and three directors appointed by the Riverstone Contributor and its affiliates, as the holder of our Series B Preferred Stock. In addition, in connection with the Business Combination, we appointed the management team of Alta Mesa to hold most of our executive officer positions.
Alta Mesa is considered our accounting predecessor and hence the historical financial statements of Alta Mesa for the three years ended December 31, 2016 and the interim period ended September 30, 2017 (unaudited) are included elsewhere in this prospectus. The (a) historical financial statements of Silver Run Acquisition Corporation II for the period from November 16, 2016 (date of inception) to December 31, 2016 and for the nine months ended September 30, 2017 (unaudited), (b) historical financial statements of Kingfisher for the year ended December 31, 2016 and the period from inception (January 30, 2015) through December 31, 2015, and for the nine months ended September 30, 2017 (unaudited), and (c) the unaudited pro forma balance sheet of Silver Run Acquisition Corporation II at September 30, 2017, and income statements for the year ended December 31, 2016 and the nine months ended September 30, 2017 are included only as Exhibits to this prospectus. Alta Mesa and Kingfisher continue to exist as separate subsidiaries of SRII Opco and those entities are separately financed, with each having debt obligations that are not obligations of the other. Consequently, references herein to Alta Mesa and to Kingfisher are to those entities and not to the Company as a whole.
Business Overview
As a result of the Business Combination, our only significant asset is our ownership of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and Kingfisher. Founded in 1987, Alta Mesa, the predecessor to our E&P Business, was an independent exploration and production company focused on the development and acquisition of unconventional oil and natural gas reserves in the eastern portion of the Anadarko Basin referred to as the STACK. The STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates. As of September 30, 2017, we had assembled a highly contiguous position of approximately 130,000 net acres largely in theup-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. As of December 31, 2016, we had 4,196 identified gross horizontal drilling locations, 2,075 of which we expect to operate. These drilling locations are in our primary target formations comprised of the Osage, Meramec and Oswego. We continue to opportunistically acquire acreage in ournon-operated locations with the goal of operating wells in these locations. As of September 30, 2017, we were operating six horizontal drilling rigs in the STACK with plans to continue to operate that number of rigs through the end of 2017.
Our Midstream Business was started by Kingfisher on January 30, 2015 for the purpose of acquiring, developing and operating midstream oil and gas assets. We primarily focus on providing crude oil gathering, gas
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gathering and processing and marketing to producers of natural gas, NGLs, crude oil and condensate in the STACK play. Our midstream energy asset network includes approximately 308 miles of existing low and high pressure pipelines, a 60 MMcf/d cryogenic natural gas processing plant, 10 MMcf/d in offtake processing, compression facilities, crude storage, NGL storage and purchasing and marketing capabilities.
Our goal is to build a premier development and acquisition company focused on horizontal drilling and gas gathering in the STACK.
Organizational Structure
The following diagram illustrates our ownership structure immediately following the Closing.
(1) | Includes (x) shares of Class C Common Stock, one share of Series B Preferred Stock owned by the Riverstone Contributor and a 5.2% limited partner interest in SRII Opco and (y) shares of Class A Common Stock owned by Fund VI Holdings. |
(2) | Includes shares of Class A Common Stock issued upon conversion of the founders shares to our Sponsor and independent directors. |
(3) | The Series A Preferred Stock and the Series B Preferred Stock will not have any voting rights (other than the right to nominate a certain number of directors for election to our board of directors as described herein) or rights with respect to dividends but are entitled to preferred distributions in liquidation in the amount of $0.0001 per share. |
(4) | Certain existing owners of Alta Mesa, including Harlan H. Chappelle, our Chief Executive Officer and a director, Michael E. Ellis, our Chief Operating Officer, Upstream and a director, and certain affiliates of Bayou City and HPS, own an aggregate 10% voting interest in Alta Mesa GP. These existing owners are a party to a voting agreement with SRII Opco and the existing owners will agree to vote their interests in Alta Mesa GP as directed by SRII Opco. |
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Additional Information
Our principal executive offices are located at 15021 Katy Freeway, Suite 400, Houston, Texas 77094, and our telephone number is(281) 530-0991. Our website is www.altamesa.net. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
Our Emerging Growth Company Status
As a company with less than $1.07 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:
• | the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations; |
• | deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting; |
• | exemption from the adoption of new or revised financial accounting standards until they would apply to private companies; |
• | exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board 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 Company; and |
• | reduced disclosure about executive compensation arrangements. |
We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following March 29, 2022, the fifth anniversary of our IPO, (ii) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion ofnon-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined inRule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We have elected to take advantage of each of the exemptions for emerging growth companies, other than the presentation of only two years of audited financial statements and related Management’s Discussion and Analysis of Financial Conditions and Results of Operations.
Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.
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The Offering
We are registering (i) the issuance by us of 34,500,000 shares of Class A Common Stock underlying the Public Warrants and (ii) the resale of 341,740,095 shares of Class A Common Stock by the selling stockholders named in this prospectus, or their permitted transferees.
Issuance of Class A Common Stock Underlying the Public Warrants
Shares of Class A Common Stock to be Issued upon Exercise of the Public Warrants | 34,500,000 shares of Class A Common Stock. |
Shares of Class A Common Stock Outstanding Prior to Exercise of the Public Warrants(1) | 169,371,730 shares of Class A Common Stock, as of February 12, 2018. |
Shares of Class A Common Stock to be Outstanding Assuming Exercise of the Public Warrants(1) | 203,871,730 shares of Class A Common Stock. |
Terms of the Public Warrants | Each Public Warrant entitles the holder to purchase one share of Class A Common Stock for $11.50 per share, at any time commencing on March 29, 2018, which is 12 months following the closing of our IPO. The Public Warrants will expire at 5:00 p.m., New York time, on February 9, 2023 (which is five years after the completion of the Business Combination) or earlier upon redemption or liquidation. |
Use of Proceeds | We expect to receive $396,750,000 in net proceeds assuming the exercise of all of our Public Warrants at the exercise price of $11.50 per share. We intend to use these net proceeds for general corporate purposes. |
Trading Market and Ticker Symbol | Our Public Warrants are listed on NASDAQ under the symbol “AMRWW.” |
Resale of Class A Common Stock by Selling Stockholders
Shares Offered by the Selling Stockholders | We are registering 341,740,095 shares of Class A Common Stock to be offered by the selling stockholders named herein. |
Terms of the Offering | The selling stockholders will determine when and how they will dispose of the shares of Class A Common Stock registered under this prospectus for resale. |
Shares Outstanding Prior to This Offering(1)(2) | As of February 12, 2018, 169,371,730 shares of Class A Common Stock, 213,402,398 shares of Class C Common Stock, three shares of Series A Preferred Stock and one share of Series B Preferred Stock were issued and outstanding. |
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Shares Outstanding After This Offering(1)(2) | 382,774,128 shares of Class A Common Stock, no shares of Class C Common Stock, three shares of Series A Preferred Stock and one share of Series B Preferred Stock will be issued and outstanding. |
Terms of the Private Placement Warrants and Forward Purchase Warrants | The Private Placement Warrants and the Forward Purchase Warrants are identical to the Public Warrants, except that for so long as they are held by the Sponsor or any of its permitted transferees, the Private Placement Warrants and the Forward Purchase Warrants: (i) may be exercised for cash or on a cashless basis, (ii) may not be transferred, assigned or sold until thirty (30) days after the completion of the Business Combination, and (iii) are not redeemable by us. |
Use of Proceeds | We will not receive any of the proceeds from the sale of shares of Class A Common Stock by the selling stockholders. We expect to receive $327,366,659 in net proceeds assuming the exercise of all of our Private Placement Warrants and the Forward Purchase Warrants (other than on a cashless basis) at the exercise price of $11.50 per share. We intend to use these net proceeds for general corporate purposes. |
Trading Market and Ticker Symbol | Our Class A Common Stock is listed on NASDAQ under the symbol “AMR.” |
(1) | The number of shares of Class A Common Stock does not include (i) the 50,000,000 shares of Class A Common Stock available for future issuance under the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan, (ii) the 15,133,333 shares of Class A Common Stock issuable upon exercise of the Private Placement Warrants, (iii) the 13,333,333 shares of Class A Common Stock issuable upon exercise of the Forward Purchase Warrants or (iv) 59,871,031 shares of Class A Common Stock that may be issuable to the Alta Mesa Contributor and the Kingfisher Contributor pursuant to theearn-out provisions of the Contribution Agreements. |
(2) | The number of shares of Class A Common Stock does not include the 34,500,000 shares of Class A Common Stock issuable upon exercise of the Public Warrants. |
For additional information concerning the offering, see “Plan of Distribution” beginning on page 178.
Risk Factors
Before investing in our securities, you should carefully read and consider the information set forth in “Risk Factors” beginning on page 10.
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Summary Historical Reserve and Summary Historical Reserve and Operating Data
The following tables present, for the periods and as of the dates indicated, summary data with respect to our estimated net proved reserves (which includes non-STACK assets) and for our STACK assets and operating data. In connection with the Alta Mesa Contribution Agreement, Alta Mesa sold a portion of its non-STACK assets for cash on December 30, 2017 and distributed the remaining non-STACK assets to its owners (other than the Riverstone Contributor) immediately prior to Closing. Alta Mesa received $22.6 million in cash for the non-STACK assets that it sold, which proceeds were used to reduce its outstanding indebtedness, resulting in an increase in the consideration payable to the owners of Alta Mesa (other than the Riverstone Contributor) in the Business Combination. Accordingly, no reserve information with respect to non-STACK assets is presented. The operating data presented includes information operating information attributable to our predecessor’s STACK and non-STACK assets.
The reserve estimates attributable to our properties as of December 31, 2016 presented in the table below are based on a reserve report prepared by our internal engineers and audited by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineer (which we refer to as the “2016 Reserve Report”). A copy of the 2016 Reserve Report is attached to this prospectus asExhibit B. 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, natural gas and natural gas liquids with respect to such properties.
See the sections entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Oil and Natural Gas Reserves” in evaluating the material presented below.
The Company | STACK Assets | |||||||||||||||
Oil and Natural Gas Liquids (MBbls) | Gas (MMcf) | Oil and Natural Gas Liquids (MBbls) | Gas (MMcf) | |||||||||||||
Proved Reserves(1) | ||||||||||||||||
Developed | 24,809 | 93,361 | 20,951 | 72,951 | ||||||||||||
Undeveloped | 61,280 | 222,644 | 59,589 | 221,308 | ||||||||||||
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Total Proved | 86,089 | 316,005 | 80,540 | 294,259 | ||||||||||||
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(1) | Our proved reserves as of December 31, 2016 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the 12 months ended on such date. For December 31, 2016, these average prices were $42.75 per Bbl for oil and $2.49 per MMBtu for natural gas. Pricing was adjusted for basis differentials by field based on our historical realized prices. The estimated realized price for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials was $15.18 per Bbl. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. |
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Nine Months Ended September 30, 2017 | Year Ended December 31, 2016 | |||||||
Net production: | ||||||||
Oil (MBbls) | 3,533 | 4,001 | ||||||
Natural gas (MMcf) | 14,073 | 13,959 | ||||||
Natural gas liquids (MBbls) | 995 | 956 | ||||||
Total (MBOE) | 6,873 | 7,284 | ||||||
Total (MMcfe) | 41,237 | 43,702 | ||||||
Average sales price per unit before hedging effects: | ||||||||
Oil (per Bbl) | $ | 48.01 | $ | 40.91 | ||||
Natural gas (per Mcf) | 2.68 | 2.22 | ||||||
Natural gas liquids (per Bbl) | 22.93 | 16.38 | ||||||
Combined (per BOE) | 33.49 | 28.87 | ||||||
Combined (per MMcfe) | 5.58 | 4.81 | ||||||
Average sales price per unit after hedging effects: | ||||||||
Oil (per Bbl) | $ | 48.25 | $ | 61.53 | ||||
Natural gas (per Mcf) | 2.81 | 2.68 | ||||||
Natural gas liquids (per Bbl) | 22.14 | 16.04 | ||||||
Combined (per BOE) | 33.75 | 41.05 | ||||||
Combined (per MMcfe) | 5.63 | 6.84 | ||||||
Average costs per BOE: | ||||||||
Lease and plant operating expense | $ | 7.25 | $ | 7.81 | ||||
Marketing and transportation expense | 3.14 | 1.83 | ||||||
Production and ad valorem taxes | 1.28 | 1.48 | ||||||
Workover expense | 0.74 | 0.65 |
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Investing in our securities involves a high degree of risk. You should consider carefully the risks and uncertainties described below, together with all of the other information in this prospectus, including our consolidated financial statements and related notes, before deciding whether to purchase any of our securities. Any of these risks may have a material adverse effect on our business, financial condition, results of operations and cash flows and our prospects could be harmed. In that event, the price of our securities could decline and you could lose part or all of your investment.
Risks Related to Our Securities and Capital Structure
Our only significant asset is the ownership of the general partner interest and a 44.2% limited partner interest in SRII Opco, and such ownership may not be sufficient to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations, including under the Tax Receivable Agreement.
We have no direct operations and no significant assets other than the ownership of the general partner interest and a 44.2% limited partner interest in SRII Opco. We will depend on SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to certain restrictions, SRII Opco generally is required to (i) make pro rata distributions to its partners, including us, in an amount at least sufficient to allow us to pay our taxes and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, as well as the financial condition and operating requirements of Alta Mesa and Kingfisher may limit our ability to obtain cash from SRII Opco. The earnings from, or other available assets of, SRII Opco and its subsidiaries, including Alta Mesa and Kingfisher, may not be sufficient to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations. SRII Opco will be treated as a partnership for U.S. federal income tax purposes and, as such, will not be subject to any entity-level U.S. federal income tax. Instead, taxable income will be allocated to holders of its SRII Opco Common Units, including us. As a result, we generally will incur income taxes on our allocable share of any net taxable income of SRII Opco. Under the terms of the agreement of limited partnership of SRII Opco (the “SRII Opco LPA”), SRII Opco is obligated to make tax distributions to holders of its SRII Opco Common Units, including us, except to the extent such distributions would render SRII Opco insolvent or are otherwise prohibited by law or any of our current or future debt agreements. In addition to tax expenses, we will also incur expenses related to our operations, our interests in SRII Opco and related party agreements, including payment obligations under the Tax Receivable Agreement, and expenses and costs of being a public company, all of which could be significant. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” To the extent that we need funds and SRII Opco or any of its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition, including our ability to pay our income taxes when due.
We may be required to take write-downs or write-offs, restructuring and impairment or other charges that could have a significant negative effect on our financial condition, results of operations and stock price, which could cause you to lose some or all of your investment.
Although we have conducted due diligence on Alta Mesa and Kingfisher, we cannot assure you that this diligence revealed all material issues that may be present in the businesses of Alta Mesa or Kingfisher, that it would be possible to uncover all material issues through a customary amount of due diligence, or that factors outside of our control will not later arise. As a result, we may be forced to later write-down orwrite-off assets, restructure our operations, or incur impairment or other charges that could result in losses. Even if our due diligence successfully identifies certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with our preliminary risk analysis. Even though these charges may be
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non-cash items and may not have an immediate impact on our liquidity, the fact that we report charges of this nature could contribute to negative market perceptions about us or our securities. In addition, charges of this nature may cause us to be unable to obtain future financing on favorable terms or at all.
The unaudited pro forma condensed consolidated combined financial information included in this prospectus may not be indicative of what our actual financial position or results of operations would have been.
The unaudited pro forma condensed consolidated combined financial information for the Company following the Business Combination in this prospectus is presented for illustrative purposes only and is not necessarily indicative of what our actual financial position or results of operations would have been had the Business Combination been completed on the dates indicated. See “Unaudited Pro Forma Condensed Consolidated Combined Financial Information of the Company” in the financial statements included elsewhere in this prospectus (see “Index to Financial Statements”).
If the Business Combination’s benefits do not meet the expectations of investors, stockholders or financial analysts, the market price of our securities may decline.
If the benefits of the Business Combination do not meet the expectations of investors or securities analysts, the market price of our securities may decline. The market values of our securities may vary significantly from their prices on the date the Contribution Agreements were executed or the date of this prospectus.
In addition, fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the Business Combination, trading in the shares of our Class A Common Stock had not been active. Accordingly, the valuation ascribed to Alta Mesa, Kingfisher and our Class A Common Stock in the Business Combination may not be indicative of the price that will prevail in the trading market following the Business Combination. If an active market for our securities develops and continues, the trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment in our securities and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.
Factors affecting the trading price of our securities may include:
• | actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us; |
• | changes in the market’s expectations about our operating results; |
• | success of our competitors; |
• | our operating results failing to meet the expectation of securities analysts or investors in a particular period; |
• | changes in financial estimates and recommendations by securities analysts concerning us or the market in general; |
• | operating and stock price performance of other companies that investors deem comparable to us; |
• | changes in laws and regulations affecting our business; |
• | commencement of, or involvement in, litigation involving us; |
• | changes in our capital structure, such as future issuances of securities or the incurrence of additional debt; |
• | the volume of shares of our Class A Common Stock available for public sale; |
• | any major change in our board or management; |
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• | sales of substantial amounts of Class A Common Stock by our directors, executive officers or significant stockholders or the perception that such sales could occur; and |
• | general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism. |
Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could depress our stock price regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.
If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.
The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us, our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.
There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and they may expire worthless; the terms of our Public Warrants may be amended without the consent of all holders.
The exercise price for our Public Warrants is $11.50 per share. There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and as such, the Public Warrants may expire worthless.
In addition, the warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the Public Warrants in a manner adverse to a holder if holders of at least 50% of the then outstanding Public Warrants approve of such amendment. Although our ability to amend the terms of the Public Warrants with the consent of at least 50% of the then outstanding Public Warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Public Warrants, shorten the exercise period or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a Public Warrant.
We may redeem the Public Warrants prior to their exercise at a time that is disadvantageous to holders, thereby making their Public Warrants worthless.
We have the ability to redeem the outstanding Public Warrants at any time after they become exercisable and prior to their expiration at a price of $0.01 per warrant, provided that (i) the last reported sale price of our
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Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within the 30trading-day period ending on the third business day before we send the notice of such redemption and (ii) on the date we give notice of redemption and during the entire period thereafter until the time the Public Warrants are redeemed, there is an effective registration statement under the Securities Act covering the shares of our Class A Common Stock issuable upon exercise of the Public Warrants and a current prospectus relating to them is available or we have elected to require the exercise of the Public Warrants on a cashless basis. Redemption of the outstanding Public Warrants could force holders of Public Warrants:
• | to exercise their Public Warrants and pay the exercise price therefor at a time when it may be disadvantageous for them to do so; |
• | to sell their Public Warrants at the then-current market price when they might otherwise wish to hold their Public Warrants; or |
• | to accept the nominal redemption price which, at the time the outstanding Public Warrants are called for redemption, is likely to be substantially less than the market value of their Public Warrants. |
Anti-takeover provisions contained in our Charter and amended and restated bylaws (the “Bylaws”), as well as provisions of Delaware law, could impair a takeover attempt.
Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:
• | up to seven of our eleven directors may be appointed by the holders of the Series A Preferred Stock and Series B Preferred Stock without any vote of the holders of Class A Common Stock; |
• | no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates; |
• | the exclusive right of our board of directors to elect a director to fill a vacancy created by the an increase in the number of directors to serve on our board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors; |
• | the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer; |
• | a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders; |
• | the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officer, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors; |
• | limiting the liability of, and providing indemnification to, our directors and officers; |
• | controlling the procedures for the conduct and scheduling of stockholder meetings; |
• | providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and |
• | advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of us. |
These provisions, alone or together, could delay hostile takeovers and changes in control of us or changes in our board of directors and management.
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As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law (the “DGCL”), which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.
A significant portion of our total outstanding shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our Class A Common Stock to drop significantly, even if our business is doing well.
Sales of a substantial number of shares of Class A Common Stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A Common Stock. The holders of our founder shares, which include our Sponsor and independent directors, and Fund VI Holdings own approximately 39% of our Class A Common Stock. Pursuant to the terms of a letter agreement entered into at the time of the IPO, the founder shares (which were converted into shares of Class A Common Stock at the Closing) may not be transferred until the earlier to occur of (i) one year after the Closing or (ii) the date on which we complete a liquidation, merger, stock exchange or other similar transaction that results in all of our public stockholders having the right to exchange their shares of Class A Common Stock for cash, securities or other property. Notwithstanding the foregoing, if the last sale price of our Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any30-trading day period commencing at least 150 days after the Closing, the shares of Class A Common Stock into which the founder shares convert will be released from these transfer restrictions.
Additionally, 90 days after Closing, the Kingfisher Contributor will have the ability to redeem or exchange up to 39,000,000 SRII Opco Common Units for shares of Class A Common Stock on aone-to-one basis, and will have this redemption or exchange right with respect to its remaining SRII Opco Common Units 180 days after Closing. The Alta Mesa Contributor and the Riverstone Contributor will also have this redemption or exchange right with respect to all of their respective SRII Opco Common Units 180 days after Closing. If the Contributors redeem or exchange all of their SRII Opco Common Units for shares of Class A Common Stock, the Alta Mesa Contributor, the Kingfisher Contributor and the Riverstone Contributor will own 36.2%, 14.4% and 5.2% of our Class A Common Stock, respectively.
In connection with the closing of our IPO, we entered into a registration rights agreement with our Sponsor and certain of our directors providing for registration rights to such parties. In addition, in connection with the Closing, we entered into a registration rights agreement with Fund VI Holdings and the Contributors, pursuant to which we are required to file the registration statement of which this prospectus is a part registering the shares of Class A Common Stock held by them for resale within 30 days following the Closing.
We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.
In connection with the completion of the Business Combination, we entered into the Tax Receivable Agreement with the Alta Mesa Contributor and the Riverstone Contributor (the “Initial Limited Partners”) and SRII Opco. Pursuant to the Tax Receivable Agreement, we will be required to make cash payments to the Initial Limited Partners and their permitted transferees (together, the “TRA Holders”) equal to 85% of the amount of tax benefits, if any, that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for Class A Common Stock (or, under certain circumstances, cash) pursuant to the redemption
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right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in our Midstream Business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings. The amount of the cash payments that we may be required to make under the Tax Receivable Agreement could be significant and is dependent upon significant future events and assumptions, including the timing of the exchanges of SRII Opco Common Units, the price of our Class A Common Stock at the time of each exchange, the extent to which such exchanges are taxable transactions and the amount of the exchanging TRA Holder’s tax basis in its SRII Opco Common Units at the time of the relevant exchange. The amount of such cash payments is also based on assumptions as to the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable and the portion of our payments under the Tax Receivable Agreement that constitute interest or give rise to depreciable or amortizable tax basis. Moreover, payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine, which tax reporting positions are subject to challenge by taxing authorities. We will be dependent on distributions from SRII Opco to make payments under the Tax Receivable Agreement, and we cannot guarantee that such distributions will be made in sufficient amounts or at the times needed to enable us to make our required payments under the Tax Receivable Agreement, or at all. Any payments made by us to the TRA Holders under the Tax Receivable Agreement will generally reduce the amount of overall cash flow that might have otherwise been available to us. To the extent that we are unable to make timely payments under the Tax Receivable Agreement for any reason, the unpaid amounts will be deferred and will accrue interest until paid by us. Nonpayment for a specified period may constitute a breach of a material obligation under the Tax Receivable Agreement, and therefore, may accelerate payments due under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are also not conditioned upon the TRA Holders maintaining a continued ownership interest in SRII Opco or us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.
We will not be reimbursed for any payments made to TRA Holders under the Tax Receivable Agreement in the event that any tax benefits are disallowed.
We will not be reimbursed for any cash payments previously made to the TRA Holders pursuant to the Tax Receivable Agreement if any tax benefits initially claimed by us are subsequently challenged by a taxing authority and are ultimately disallowed. Instead, any excess cash payments made by us to a TRA Holder will be netted against any future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement. However, a challenge to any tax benefits initially claimed by us may not arise for a number of years following the initial time of such payment or, even if challenged early, such excess cash payment may be greater than the amount of future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement and, as a result, there might not be future cash payments from which to net against. The applicable U.S. federal income tax rules are complex and factual in nature, and there can be no assurance that the Internal Revenue Service (the “IRS”) or a court will not disagree with our tax reporting positions. As a result, it is possible that we could make cash payments under the Tax Receivable Agreement that are substantially greater than our actual cash tax savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.
Certain of the TRA Holders have substantial control over us, and their interests, along with the interests of other TRA Holders, in our business may conflict with yours.
The TRA Holders may receive payments from us under the Tax Receivable Agreement upon any redemption or exchange of their SRII Opco Common Units, including the issuance of shares of our Class A Common Stock upon any such redemption or exchange. As a result, the interests of the TRA Holders may conflict with the interests of holders of our Class A Common Stock. For example, the TRA Holders may have
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different tax positions from us which could influence their decisions regarding whether and when to dispose of assets, whether and when to incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement, and whether and when we should terminate the Tax Receivable Agreement and accelerate our obligations thereunder. In addition, the structuring of future transactions may take into consideration tax or other considerations of TRA Holders even in situations where no similar considerations are relevant to us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.
In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.
The Tax Receivable Agreement provides that if we breach any of our material obligations under the Tax Receivable Agreement or if, at any time, we elect an early termination of the Tax Receivable Agreement, then the Tax Receivable Agreement will terminate and our obligations, or our successor’s obligations, to make payments under the Tax Receivable Agreement would accelerate and become immediately due and payable. The amount due and payable in those circumstances is determined based on certain assumptions, including an assumption that we would have sufficient taxable income to fully utilize all potential future tax benefits that are subject to the Tax Receivable Agreement. We may need to incur debt to finance payments under the Tax Receivable Agreement to the extent our cash resources are insufficient to meet our obligations under the Tax Receivable Agreement as a result of timing discrepancies or otherwise.
As a result of the foregoing, (i) we could be required to make cash payments to the TRA Holders that are greater than the specified percentage of the actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement, and (ii) we would be required to make a cash payment equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combination, or other changes of control due to the additional transaction costs a potential acquirer may attribute to satisfying such obligations. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.
The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.
On December 22, 2017, President Trump signed into law the final version of the tax reform bill that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). The tax reform bill, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, a limitation of the deduction for net operating loss carryforwards to 80% of current year taxable income, an indefinite net operating loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time, and the modification or repeal of many business deductions and credits. We continue to examine the impact this tax reform legislation may have on our business. Notwithstanding the reduction in the corporate income tax rate, the overall impact of the tax reform bill is uncertain and our business and financial condition could be adversely affected. The impact of this tax reform on holders of our Class A Common Stock is also uncertain and could be adverse.
The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
We qualify as an “emerging growth company” as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not
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emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions fromsay-on-pay,say-on-frequency andsay-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following March 29, 2022, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.07 billion or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held bynon-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion innon-convertible debt during the prior three-year period.
In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply tonon-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant standards used.
We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.
Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their Class A Common Stock and Public Warrants.
We believe that we are a United States real property holding corporation (a “USRPHC”). As a result,Non-U.S. holders (defined below in the section entitled “Material U.S. Federal Income Tax Consequences toNon-U.S. Holders”) that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock or Public Warrants during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock or Public Warrants and may be required to file a U.S. federal income tax return. If you are aNon-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.
Risks Related to our E&P Business
Oil and natural gas prices are highly volatile and depressed prices can significantly and adversely affect our financial condition and results of operations.
Our revenue, profitability and cash flows depend upon the prices for oil, natural gas and natural gas liquids. The prices we receive for oil and natural gas production are volatile and a decrease in prices can materially and adversely affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows.
Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to change in the future. In particular, the prices of oil and natural gas declined dramatically after
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the second half of 2014. Oil prices continued to fluctuate during 2016. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the 12 months ended December 31, 2016 for a barrel of oil ranged from a high of $52.17 in December 2016 to a low of $30.62 in February 2016, and the price for an MMBtu of natural gas ranged from a high of $3.23 in December 2016 to a low of $1.71 in March 2016. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the 12 months ended September 30, 2017 for a barrel of oil ranged from a high of $53.46 in February 2017 to a low of $45.20 in June 2017, and the price for an MMBtu of natural gas ranged from a high of $3.93 in January 2017 to a low of $2.63 in March 2017.
Continued fluctuations in oil and natural gas prices, price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves. The average realized price, excluding hedge settlements, at which we sold oil from the STACK in the nine months ended September 30, 2017 was $47.97 per barrel compared to $38.75 per barrel in the nine months ended September 30, 2016. The average realized price, excluding hedge settlements, at which we sold oil from the STACK in the year ended December 31, 2016 was $41.16 per barrel compared to $45.90 per barrel in the year ended December 31, 2015. The average realized price, excluding hedge settlements, at which we sold oil from the STACK in the year ended December 31, 2015 was $45.90 per barrel compared to $89.34 per barrel in 2014.
Because the oil price we are required to use to estimate our future net cash flows is the average first day of the month price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if prices increase.
Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:
• | the domestic and foreign supply of and demand for oil and natural gas; |
• | the price and quantity of foreign imports of oil and natural gas; |
• | changes in federal regulations removingdecades-old prohibition of the export of crude oil production in the U.S.; |
• | federal regulations applicable to exports of liquefied natural gas (“LNG”), including the recently initiated exports of LNG liquefied from natural gas produced in the lower 48 states of the U.S.; |
• | actions taken by members of the Organization of Petroleum Exporting Countries and other oil producing nations in connection with their arrangements to maintain oil price and production controls; |
• | the level of consumer product demand; |
• | weather conditions; |
• | domestic and foreign governmental regulations, including environmental initiatives and taxation; |
• | overall domestic and global economic conditions; |
• | the value of the dollar relative to the currencies of other countries; |
• | stockholder activism or activities bynon-governmental organizations to restrict the exploration, development and production of oil and natural gas in order to minimize emissions of carbon dioxide, a greenhouse gas (“GHG”); |
• | political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia and acts of terrorism or sabotage; |
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• | the proximity and capacity of natural gas pipelines and other transportation facilities to our production; |
• | technological advances affecting energy consumption; |
• | the price and availability of alternative fuels; and |
• | the impact of energy conservation efforts. |
Substantially all of our production is sold to purchasers under contracts with market-based prices. Lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves.
Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.
The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. Our estimated STACK capital expenditures for 2018 and 2017 are $552 million and $349 million, respectively. Our STACK capital expenditures for 2016 totaled $209 million, including $11 million for acquisitions. Our STACK capital expenditures for 2015 totaled $179 million, including $48 million for acquisitions. We have funded development and operating activities primarily through equity capital raised from our affiliates, through borrowings, through the issuance of debt and through internal operating cash flows. We intend to finance our future capital expenditures predominantly with cash flows from operations and with the proceeds we receive in the Business Combination.
If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:
• | the estimated quantities of our proved oil and natural gas reserves; |
• | the amount of oil and natural gas we produce from existing wells; |
• | the prices at which we sell our production; and |
• | our ability to acquire, locate and produce new reserves. |
If our revenues or the borrowing base under Alta Mesa’s senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Alta Mesa’s senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under Alta Mesa’s senior secured revolving credit facility is not sufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of its operations relating to development of its prospects, which in turn could lead to a decline in our reserves and production and could adversely affect Alta Mesa’s business, results of operations, financial conditions and ability to make payments on its outstanding indebtedness.
External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and may be forced to limit or defer our planned oil and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations.
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Our business strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.
Our operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:
• | landing our wellbore in the desired drilling zone; |
• | staying in the desired drilling zone while drilling horizontally through the formation; |
• | running our production casing the entire length of the wellbore; and |
• | running tools and other equipment consistently through the horizontal wellbore. |
The difficulties that we face while completing our wells include the following:
• | designing and executing the optimum fracture stimulation program for a specific target zone; |
• | running tools the entire length of the wellbore during completion operations; and |
• | cleaning out the wellbore after completion of the fracture stimulation. |
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.
Our producing properties are located in a limited geographic area, making us vulnerable to risks associated with having geographically concentrated operations.
Our producing properties are geographically concentrated in the STACK. Because of this concentration, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the STACK may be adversely affected by severe weather events such as floods, ice storms and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to beshut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.
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Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop identified locations depends on a number of uncertainties, including oil, natural gas and natural gas liquids 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 uncertainties, we do not know if the potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
Furthermore, our estimate of the number of our net drilling locations is based on a number of assumptions, which may prove to be incorrect. For example, we have estimated the number of net drilling locations based on our expected working interests in each gross drilling location based on our existing working interest associated with our acreage applicable to such drilling location and any assumed dilution of such working interest based on any expected unitization (or imposed forced pooling) of such acreage with adjacent properties controlled by third parties. Our assumptions regarding the impact on any such unitization or forced pooling on our working interest in our gross drilling locations may be incorrect and may result in more dilution of our working interest than anticipated, which would result in a reduction of our net drilling locations. See “Risk Factors—We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest in wells we propose to drill on our STACK acreage due to changes in third-party interest owners’ ability or desire to participate in our wells or possible future regulatory changes.”
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 the capital required. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us 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 assets are subject to leases that will expire over the next several years unless production is established on units containing acreage.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, we do have provisions in some of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices decline or we are unable to fund our anticipated capital program, there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs). Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
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We depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.
Lower oil, natural gas and natural gas liquids prices may cause us to recordnon-cash write-downs, which could negatively impact our results of operations.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and 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 anon-cash charge to earnings. For the year ended December 31, 2016, we recognized impairment expense related to our assets in the STACK of approximately $0.4 million as a result of lower forecasted commodity prices. We recognized impairment expense related to the STACK for the 12 months ended December 31, 2015 of $15.7 million as a result of lower forecasted commodity prices.
In the future, we may recognize significant impairments of proved oil and gas properties and impairments of unproved oil and gas properties as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2016, our estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value related to the STACK of approximately $463.2 million indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if oil and natural gas prices decline by 10%. We estimate that, if this depletion group becomes impaired in a future period, we could recognizenon-cash impairments related to the STACK in that period in excess of $1.3 million. It is also reasonably foreseeable that prolonged low or further declines in commodity prices, further changes to our drilling plans in response to lower prices or increases in drilling or operating costs could result in other additional impairments.
Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2016. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the
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economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12 month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.
The present value of future net revenues from our proved reserves or“PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.
It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the12-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding 12 months from the date of the report without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
• | actual prices we receive for crude oil and natural gas; |
• | actual cost of development and production expenditures; |
• | the amount and timing of actual production; |
• | transportation and processing; and |
• | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves and thus their actual present value. In addition, the 10% discount factor we use when calculating thePV-10 value may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used our present value estimate as of December 31, 2016. If oil and natural gas prices declined by 10% from our estimate, then our NYMEXPV-10 value for the STACK as of December 31, 2016 would have decreased by approximately $290 million to $909 million.
SEC rules could limit our ability to book additional PUDs in the future.
The SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill, or change our development plans to delay the drilling of, those wells within the required five-year timeframe.
Approximately 74% of our total estimated SEC net proved reserves in the STACK at December 31, 2016 were PUDs requiring substantial capital expenditures and may ultimately prove to be less than estimated.
Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2016, approximately 96.5 MMBOE (74%) of our STACK total estimated SEC net proved reserves were undeveloped. The reserve data included in our 2016 Reserve Report assumes that substantial capital expenditures will be made to developnon-producing reserves. The calculation of our estimated STACK net proved reserves as of December 31, 2016 assumed that we would spend $606 million, including plugging and abandonment costs, to develop our estimated PUDs, including an estimated $181 million during 2017. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with
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industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated PUDs over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, declines in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. As a result of depressed oil and natural gas prices, we reduced the budgeted capital expenditures for the development of undeveloped reserves in 2016. These delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, results of operations and future cash flows.
As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.
We may experience difficulty in achieving and managing future growth.
We believe that our future success depends on our ability to manage the 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.
Additionally, future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
• | the results of our drilling program; |
• | hydrocarbon prices; |
• | our ability to develop existing prospects; |
• | our ability to obtain leases or options on properties for which we has3-D seismic data; |
• | our ability to acquire additional3-D seismic data; |
• | our ability to identify and acquire new exploratory prospects; |
• | our ability to continue to retain and attract skilled personnel; |
• | our ability to maintain or enter into new relationships with project partners and independent contractors; and |
• | our access to capital. |
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We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and natural gas liquids we produce.
The availability of a ready market for any oil, natural gas and natural gas liquids we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. While we believe that we would be able to locate alternative purchasers, we cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.
The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot provide assurance that we will continue to maintain production levels through drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
We have made and may in the future make acquisitions of businesses or properties that complement or expand our current business. 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. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our purchase of the business or property. 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. In the course of our due diligence, we may not inspect every aspect of a business we acquire and we cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when an inspection is made.
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. Our failure to achieve consolidation savings, to incorporate 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, Alta Mesa’s senior secured revolving credit facility and the indenture governing its 7.875% senior unsecured notes due December 15, 2024 (the “2024 Notes”) impose certain limitations on its ability to enter into mergers or combination transactions. Alta Mesa’s senior secured revolving credit facility and the indenture governing its 2024 Notes also limit Alta Mesa’s ability to incur certain indebtedness, which could indirectly limit its ability to engage in acquisitions of businesses.
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Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.
Our business activities are subject to operational risks, including:
• | damages to equipment caused by natural disasters such as earthquakes and adverse weather conditions, including tornadoes and flooding; |
• | facility or equipment malfunctions; |
• | pipeline or tank ruptures or spills; |
• | surface fluid spills, produced water contamination and surface or groundwater contamination resulting from petroleum constituents or hydraulic fracturing chemical additions; |
• | fires, blowouts, craterings and explosions; and |
• | uncontrollable flows of oil or natural gas or well fluids. |
In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.
Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.
As is customary in the industry, we maintain insurance against some, but not all, of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our 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 “—Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”
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.
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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; |
• | regulation limiting the emission of 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, accidents or other unexpected operational events; |
• | 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. |
Our hedging activities could result in financial losses or could reduce our net income.
To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have entered and may continue to enter into hedging arrangements for a significant portion of our production. As of September 30, 2017, we have hedged approximately 73% of our total company-forecasted PDP production through 2019 at weighted average annual floor prices ranging from $3.18 per MMBtu to $4.43 per MMBtu for natural gas and $50.00 per Bbl to $51.37 per Bbl for oil, with the majority of the hedged volumes in 2017. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that us will not realize the benefit of the hedge.
Our ability to use hedging transactions to protect us from future price declines will be dependent upon prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes.
Our policy has been to hedge a significant portion of our near-term estimated production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.
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Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if counterparty fails to perform under a derivative contract. This risk of counterpartynon-performance is of particular concern given the disruptions that have occurred in the financial markets and the significant declines in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in 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. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.
During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Our use of2-D and3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted,2-D and3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing3-D seismic data technology with respect to certain of our projects. The use of2-D and3-D seismic data and other advanced technologies requires greaterpre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.
We often gather2-D and3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze2-D and3-D seismic data without having an opportunity to attempt to benefit from those expenditures.
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 properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Our competitors may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, the oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. Our inability to compete effectively with our competitors could have a material adverse impact on our business activities, financial condition and results of operations.
We may not be able to keep pace with technological developments in the oil and natural gas 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,
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we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and 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 or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Deficiencies of title to our leased interests could significantly affect our financial condition.
If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is the practice of our management, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.
Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leasehold may adversely impact our ability in the future to increase production and reserves.
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 shale oil and natural gas exploration and production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. However, our access to such water supplies may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. If we are unable to obtain sufficient amounts of water to use in our operations from local sources, our ability to perform hydraulic fracturing operations could be restricted or made more costly, or we otherwise may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
Our operations may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.
We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide
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range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:
• | the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes variouspre-construction, monitoring and reporting requirements and is relied upon by the U.S. Environmental Protection Agency (“EPA”) as authority for adopting climate change regulatory initiatives relating to GHG emissions; |
• | the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States; |
• | the Oil Pollution Act (“OPA”), which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States; |
• | the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations; |
• | the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements for the generation, treatment, storage, transport disposal and cleanup ofnon-hazardous and hazardous wastes; |
• | the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur as well as imposes liability on present and certain past owners and operations of sites were hazardous substance releases have occurred or are threatening to occur; |
• | the Emergency Planning and Community Right to Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories; |
• | the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas; and |
• | the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments or environmental impact statements. |
These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws and analogous state laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and more stringent laws and regulations may be adopted in the future. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.
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Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.
Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill and the disposal of saltwater produced from such wells, among other matters. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma statutory forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and operating results.
We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest in wells we propose to drill on our STACK acreage due to changes in third-party interest owners’ ability or desire to participate in our wells or possible future regulatory changes.
In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to increase our working interest in drilling units for wells we propose to drill as operator on our STACK acreage, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. In recent years, the collective working interest of third-party owners of mineral rights in our drilling units who have elected to participate in our wells has been relatively low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic oil and gas play in the current price and cost environment and the resultant consolidation of acreage in producers with greater access to capital, we believe that third-party interest holders may be more likely to bear their share of the costs of the proposed future wells we propose to drill on our acreage. Thus, our ability to use Oklahoma forced pooling procedures to increase our working interest in proposed wells may be more difficult to accomplish. In addition, future changes in laws and regulations in Oklahoma affecting the forced pooling process could result in changes in economics and the level of participation in drilling by third-party interest owners and adversely affect our ability to increase our interest in wells that we propose.
The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation ofover-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.
In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016 are-proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC hasre-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.
The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercialend-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear
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certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercialend-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.
All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercialend-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The “Volcker Rule” provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercialend-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.
As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.
If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
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.
Our exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.
We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil
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and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.
Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before the U.S. Congress (“Congress”), the Federal Energy Regulatory Commission, (“FERC”), various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
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.
Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or FERC, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005 (“EPAct”), FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties 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 otherwisenon-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.
Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration ofcap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce
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these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. Moreover, in November 2016, the EPA issued an Information Collection Request (“ICR”) seeking information about methane emissions from facilities and operations in the oil and natural gas industry, but on March 2, 2017 the EPA announced that it was withdrawing the ICR so that the agency may further assess the need for the information that it was collecting through the request. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. The United States is one of more than 120 nations having ratified or otherwise consented to the agreement; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. With the change in Presidential administration, the ongoing commitment of the United States to the Paris Agreement is unclear. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement, if it chooses to do so, are unclear at this time.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we produce and lower the value of our reserves.
Finally, it should be noted 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 such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient ornon-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could increase our costs of doing business, impose additional operating restrictions or delays and adversely affect our production.
Hydraulic fracturing is an essential and common practice used to stimulate production of oil and natural gas from dense subsurface rock formations, such as shales. We routinely apply hydraulic fracturing techniques in many of our operations to stimulate production of hydrocarbons, particularly natural gas. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production.
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Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s Underground Injection Control (“UIC”) program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In other examples, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, in 2015, the Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands, which has been challenged in court. However, the BLM is in the process of rescinding the 2015 rule.
Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.
In addition, some states, including Oklahoma where we operate, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although Oklahoma has taken steps to limit the authority of local governments to regulate oil and natural gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our production and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.
Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from our drilling and production activities, which could have a material adverse effect on our business.
We dispose of produced water gathered from our operations pursuant to permits issued to us or third-party vendors by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.
One such concern relates to recent seismic events near underground injection wells used for the disposal of produced water resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including
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Oklahoma, where we operate. In response to these concerns regarding induced seismicity, regulators in some states, including Oklahoma, have imposed, and other states are considering imposing, additional requirements in the permitting of produced water injection wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The Oklahoma Corporation Commission (“OCC”) has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. More recently, in December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and natural gas wastewater injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state.
Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection well locations or otherwise or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.
Laws and regulations pertaining to threatened and endangered species or protective of environmentally sensitive areas could delay or restrict our operations and cause us to incur significant costs.
Our operations may be adversely affected by seasonal or permanent restrictions or costly mitigation measures imposed under various federal and state statutes in order to protect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. Federal statutes, as amended from time to time, that are protective of these species, birds and environmentally sensitive areas include the ESA, the Migratory Bird Treaty Act (the “MBTA”), the CWA, the CERCLA and the OPA. For example, to the extent that species are listed under the ESA or similar state laws and live in areas where our oil and natural gas exploration and production activities are conducted, our ability to conduct or expand operations and construct facilities could be limited or we could be forced to incur material additional costs. Moreover, our operations may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.
Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could
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result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and natural gas development. As a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous specified species as endangered or threatened under the ESA pursuant to specified timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. If harm to protected species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and natural gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or time delays or limitations on our operations.
We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.
Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and natural gas liquid prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor, especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. Recently, there has been increased drilling activity in the STACK. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.
The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.
The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. See “Our E&P Business—Environmental and Occupational Safety and Health Matters” and “Our E&P Business—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
We have limited control over properties which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations, an operator’s financial difficulties, including as a result of price volatility or an operator’s breach of the applicable agreements could reduce our production and revenues.
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The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.
Oil and gas exploration and production activities are complex and involve risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
We depend on key personnel, the loss of any of whom could materially adversely affect future operations.
Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintainkey-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.
We operate in an area of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the STACK, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.
We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.
The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling.
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The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.
Alta Mesa’s senior secured revolving credit facility and the indenture governing its 2024 Notes have restrictive covenants that could limit its growth, financial flexibility and its ability to engage in certain activities. Since Alta Mesa is our subsidiary, all of the effects of these debt facilities on Alta Mesa apply equally to us.
Alta Mesa’s senior secured revolving credit facility and the indenture governing its 2024 Notes have restrictive covenants that could limit its growth, financial flexibility and its ability to engage in activities that may be in Alta Mesa’s long-term best interests. Alta Mesa’s senior secured revolving credit facility and the indenture governing its 2024 Notes also contain covenants that, among other things, limit Alta Mesa’s ability to:
• | incur additional indebtedness; |
• | sell assets; |
• | guaranty or make loans to others; |
• | make investments; |
• | enter into mergers; |
• | make certain payments and distributions; |
• | enter into or be party to hedge agreements; |
• | amend its organizational documents; |
• | incur liens; and |
• | engage in certain other transactions without the prior consent of its lenders. |
In addition, Alta Mesa’s senior secured revolving credit facility requires Alta Mesa to maintain certain financial ratios or to reduce Alta Mesa’s indebtedness if it is unable to comply with such ratios, which may limit Alta Mesa’s ability to obtain future financings to withstand a future downturn in its business or the economy in general or to otherwise conduct necessary corporate activities. Alta Mesa may also be prevented from taking advantage of business opportunities that arise because of these limitations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa—Senior Notes” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa—Senior Secured Revolving Credit Facility.”
Alta Mesa’s failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of its indebtedness. If that occurs, Alta Mesa 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 Alta Mesa.
Any significant reduction in Alta Mesa’s borrowing base under its senior secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact Alta Mesa’s ability to fund its operations, and Alta Mesa may not have sufficient funds to repay borrowings under its senior secured revolving credit facility if required as a result of a borrowing base redetermination.
Availability under Alta Mesa’s senior secured revolving credit facility is currently subject to a borrowing base of $350.0 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa—Senior Secured Revolving Credit Facility.” The borrowing base is subject to scheduled semiannual and other elective unscheduled borrowing base redeterminations and is based on the value of Alta Mesa’s oil and natural gas reserves as determined by the lenders under its senior secured revolving credit facility and other factors deemed relevant by its lenders. Declines in prices for oil and natural gas may cause Alta
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Mesa’s banks to reduce the borrowing base under its senior secured revolving credit facility. Any significant reduction in Alta Mesa’s borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact its liquidity and its ability to fund its operations and, as a result, may have a material adverse effect on Alta Mesa’s financial condition, results of operations and cash flows. Further, if the outstanding borrowings under Alta Mesa’s senior secured revolving credit facility were to exceed the borrowing base as a result of any such redetermination, Alta Mesa would be required to repay the excess. Alta Mesa may not have sufficient funds to make such repayments. If Alta Mesa does not have sufficient funds and it is otherwise unable to negotiate renewals of its borrowings or arrange new financing, it may have to sell significant assets. Any such sale could have a material adverse effect on Alta Mesa’s business and financial results.
If Alta Mesa is unable to comply with the restrictions and covenants in its debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.
If Alta Mesa is unable to comply with the restrictions and covenants in its debt agreements, there could be a default under the terms of these agreements. Alta Mesa’s ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond its control. As a result, Alta Mesa cannot assure that it will be able to comply with these restrictions and covenants or meet such financial ratios and tests.
If Alta Mesa is unable to generate sufficient cash flow and is otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on its indebtedness, or if Alta Mesa otherwise fails to comply with the various covenants, including financial and operating covenants in the instruments governing its indebtedness (including covenants in its senior secured revolving credit facility or the indenture governing the 2024 Notes), Alta Mesa could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under its senior secured revolving credit facility could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against its assets, and it could be forced into bankruptcy or liquidation. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, Alta Mesa’s assets might not be sufficient to repay in full all of its outstanding indebtedness and it may be unable to find alternative financing. Even if Alta Mesa could obtain alternative financing, it might not be on terms that are favorable or acceptable to it. Additionally, Alta Mesa may not be able to amend its debt agreements or obtain needed waivers on satisfactory terms.
Alta Mesa’s borrowings under its senior secured revolving credit facility expose us to interest rate risk.
Alta Mesa’s earnings are exposed to interest rate risk associated with borrowings under its senior secured revolving credit facility. Alta Mesa’s senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will Alta Mesa’s interest costs, which may have a material adverse effect on its financial condition and results of operations. Alta Mesa may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.
To service its indebtedness, Alta Mesa requires a significant amount of cash, and its ability to generate cash will depend on many factors beyond its control.
Alta Mesa’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends in part on its ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond Alta Mesa’s control. Alta Mesa cannot provide assurance that it will generate sufficient cash flow from operations, that it will realize operating improvements on schedule or that future borrowings will be available to it in an
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amount sufficient to enable it to service and repay its indebtedness or to fund its other liquidity needs. If Alta Mesa is unable to satisfy its debt obligations, it may have to undertake alternative financing plans, such as:
• | refinancing or restructuring its debt; |
• | selling assets; |
• | reducing or delaying capital investments; or |
• | seeking to raise additional capital. |
However, any alternative financing plans that it undertakes, if necessary, may not allow Alta Mesa to meet its debt obligations.
Alta Mesa cannot provide assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to it or that additional financing could be obtained on acceptable terms. Alta Mesa’s inability to generate sufficient cash flows to satisfy its debt obligations, or to obtain alternative financing, could materially and adversely affect its business, financial condition, results of operations and prospects.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.
Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in us have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.
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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data systems. If any such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Risks Related to our Midstream Business
We must continually compete for crude oil, natural gas and NGL supplies, and any decrease in supplies of such commodities could adversely affect our financial condition, results of operations or cash flows.
In order to maintain or increase throughput levels in our gathering system and asset utilization rates at our processing plant, we must continually contract for new product supplies. We may not be able to obtain additional contracts for crude oil, natural gas and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering system. If we are unable to maintain or increase the volumes on our system by accessing new supplies to offset the natural decline in reserves, our business and financial results could be adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new crude oil and natural gas reserves. During 2016, we saw lower drilling activity due to low commodity prices. Although drilling activity improved during 2016 and 2017, we could see downward pressure on future drilling activity in the STACK play if commodity prices decline, which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to our system and assets. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A continued decrease in the level of drilling activity or a material decrease in production in our area of operation for a prolonged period, as a result of continued depressed commodity prices or otherwise, likely would adversely affect our financial condition, results of operations and cash flow.
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Any decrease in the volumes that we gather, process, store or transport would adversely affect our financial condition, results of operations or cash flows.
Our financial performance depends to a large extent on the volumes of crude oil, natural gas and NGLs gathered, processed, stored and transported on our assets. Decreases in the volumes of crude oil, natural gas and NGLs we gather, process, store or transport would directly and adversely affect our financial condition, results of operations or cash flows. These volumes can be influenced by factors beyond our control, including:
• | environmental or other governmental regulations; |
• | weather conditions; |
• | increases in storage levels of crude oil, natural gas and NGLs; |
• | increased use of alternative energy sources; |
• | decreased demand for crude oil, natural gas and NGLs; |
• | continued fluctuation in commodity prices, including the prices of crude oil, natural gas and NGLs; |
• | economic conditions; |
• | supply disruptions; |
• | availability of supply connected to our systems; and |
• | availability and adequacy of infrastructure to gather and process supply into and out of our systems. |
The volumes of crude oil, natural gas and NGLs gathered, processed and transported on our assets also depend on the production from the region that supplies our systems. Supply of crude oil, natural gas and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our system, we must obtain new sources of crude oil, natural gas and NGLs. The primary factors affecting our ability to obtainnon-dedicated sources of crude oil, natural gas, and NGLs include (i) the level of successful leasing, permitting and drilling activity in our areas of operation, (ii) our ability to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our area of operation, the amount of reserves associated with wells connected to our system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.
Construction of our Phase II assets subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations or cash flows.
We are engaged in the construction of our Phase II assets, including an expansion of our cryogenic processing plant, some of which will take a number of months before commercial operation. The construction of these Phase II assets is complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of the Phase II assets could adversely affect our financial condition, results of operations or cash flows. The construction of pipelines and gathering and processing and storage facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.
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Our construction of new assets may be more expensive than anticipated and may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks that could adversely affect our financial condition, results of operations or cash flows.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control including potential protests or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain newrights-of-way and permits prior to constructing new pipelines or facilities. We may be unable to timely obtain suchrights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain newrights-of-way or to expand or renew existingrights-of-way. If the cost of renewing or obtaining newrights-of-way increases, our cash flows could be adversely affected.
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Performance of our operations requires that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility and on our financial condition, results of operations and cash flows.
Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.
We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than anticipated.
We typically do not obtain, on a regular basis, independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes transported
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on our gathering systems or that we otherwise service in the future could be less than anticipated. A decline in the volumes could adversely affect our financial condition, results of operations or cash flows.
Restrictions in Kingfisher’s credit facility could adversely affect its financial condition, results of operations or cash flows. Since Kingfisher is our subsidiary, all of the effects of these debt facilities on Kingfisher apply equally to us.
Kingfisher is a party to a $200 million credit agreement that matures on August 8, 2021, with quarterly interest payments due on Base Rate loans. Kingfisher’s interest rates depend upon its consolidated leverage ratio and Kingfisher can elect to borrow on a Eurodollar Loan or Base Rate Loan basis. Both the Eurodollar Loan and Base Rate Loan margins are subject to minimum rates established by third-party institutions, such as, but not limited to the Federal Reserve. For example, if Kingfisher elects to borrow a Base Rate Loan, the interest rate would be 4.25%, plus the applicable margin pricing level. Currently, Kingfisher is at tier 2 of the pricing level resulting in an applicable margin of 2.0% for an effective annual interest rate of 6.25%. The terms of this credit agreement limit Kingfisher’s ability to, among other things:
• | incur or guarantee additional debt; |
• | make certain investments and acquisitions; |
• | incur certain liens or permit them to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge or consolidate with another company; and |
• | transfer, sell or otherwise dispose of assets. |
The Kingfisher credit facility also contains covenants requiring it to maintain certain financial ratios. Kingfisher’s ability to meet those financial ratios and tests can be affected by events beyond its control, and Kingfisher cannot assure you that it will meet any such ratios and tests.
The provisions of the Kingfisher credit facility may affect its ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the credit facility could result in a default or an event of default that could enable Kingfisher’s lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of Kingfisher’s debt is accelerated, its assets may be insufficient to repay such debt in full.
Our exposure to commodity price risk may change over time.
We generate substantially all of our revenues from our Midstream Business pursuant tofee-based contracts under which we are paid based on the volumes that we gather, process and transport, rather than the underlying value of the commodity, in order to minimize our exposure to commodity price risk. However, we are a party tofee-based contracts that have a small portion ofpercent-of-proceeds contractual mix, but the portion ofpercent-of-proceeds does not exceed 6.0% for any one contract. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and NGL prices could adversely affect our financial condition, results of operations or cash flows.
If third-party pipelines or other midstream facilities interconnected to our gathering, processing, storage or transportation systems become partially or fully unavailable, or if the volumes we gather, process, store or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our gross profit and cash flow could be adversely affected.
Our gathering, processing, storage and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-
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party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes we gather or transport do not meet the product quality requirements of such pipelines or facilities, our gross profit and cash flows could be adversely affected.
The midstream industry is highly competitive, and increased competitive pressure could adversely affect our financial condition, results of operations or cash flows.
We compete with similar midstream enterprises in our area of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Our competitors include large crude oil and natural gas companies that have greater financial resources and access to supplies of crude oil, natural gas and NGLs than us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. Excess pipeline capacity in the region served by our intrastate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain or increase current revenues and cash flows could be adversely affected by the activities of our competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available toend-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, storage and transportation services. All of these competitive pressures could adversely affect our financial condition, results of operations or cash flows.
If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired midstream assets with our existing asset base, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make midstream acquisitions that result in an increase in cash generated from operations. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth will be limited.
From time to time, we may evaluate and seek to acquire midstream assets or businesses that we believe complement our existing business and related assets. We may acquire midstream assets or businesses that we plan to use in a manner materially different from its prior owner’s use. Any acquisition involves potential risks, including:
• | the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area; |
• | the diversion of management’s attention from other business concerns; |
• | the failure to realize expected volumes, revenues, profitability or growth; |
• | the failure to realize any expected synergies and cost savings; |
• | the coordination of geographically disparate organizations, systems and facilities; |
• | the assumption of unknown liabilities; |
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• | the loss of customers or key employees from the acquired businesses; and |
• | potential environmental or regulatory liabilities and title problems. |
The assessment by our management of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our financial condition, results of operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly.
We may not be able to retain existing midstream customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of our existing contracts with our midstream customers at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including competition from other midstream service providers and the price of, and demand for, crude oil, natural gas and NGLs in the markets we serve. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
If our midstream assets become subject to FERC regulation or federal, state or local regulations or policies change, our financial condition, results of operations and cash flows could be materially and adversely affected.
We believe that our gathering and transportation operations are exempt from regulation by FERC under the NGA. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on acase-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by us are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGPA and the rules and regulations promulgated under those statutes. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.
Unlike natural gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the ICA. Whether a crude oil or NGL shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the crude oil’s or NGL’s final destination, absent a break in the interstate movement. We believe that the crude oil and NGL pipelines in our gathering system meet the traditional tests FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on our crude oil and NGL pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of our system, and may change over time. If FERC were to consider the status of an individual facility and the character of a crude oil or NGL shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs, and, depending on the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.
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If we fail to comply with all the applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, for instance, FERC has civil penalty authority to impose penalties for current violations of the NGA or NGPA of up to $1,213,503 per day for each violation. The maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct.
Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and Oklahoma has adopted complaint-based or other limited economic regulation of natural gas gathering activities.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
The pipelines we own and operate are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the OCC could result in substantial expenditures for testing, repairs and replacement. If our pipelines fail to meet the safety standards mandated by the OCC or the DOT regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which cannot be estimated at this time.
Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. Because certain of our operations are located around areas that may become more populated areas, such as the STACK play, we may incur expenses to mitigate noise, odor and light that may be emitted in our operations and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.
In addition to the foregoing risks affecting our Midstream Business, most of the risks that apply to our E&P Business also apply to our Midstream Business.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial condition, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project”, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about:
• | the benefits of the Business Combination; |
• | the future financial performance of the combined company following the Business Combination; |
• | our business strategy; |
• | our reserve quantities and the present value of our reserves; |
• | our exploration and drilling prospects, inventories, projects and programs; |
• | our horizontal drilling, completion and production technology; |
• | our ability to replace the reserves we produce through drilling and property acquisitions; |
• | our financial strategy, liquidity and capital required for our development program; |
• | future oil and natural gas prices; |
• | the supply and demand for natural gas, NGLs, crude oil and midstream services; |
• | the timing and amount of future production of oil and natural gas; |
• | our hedging strategy and results; |
• | the drilling and completion of wells, including statements about future horizontal drilling plans; |
• | competition and government regulation; |
• | our ability to obtain permits and governmental approvals; |
• | changes in the Oklahoma forced pooling system; |
• | pending legal and environmental matters; |
• | our future drilling plans; |
• | our marketing of oil, natural gas and natural gas liquids; |
• | our leasehold or business acquisitions; |
• | our costs of developing our properties; |
• | our liquidity and access to capital; |
• | our ability to hire, train or retain qualified personnel; |
• | general economic conditions; |
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• | operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, NGLs, crude oil and midstream products; |
• | our future operating results, including initial production values and liquid yields in our type curve areas; |
• | disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent; |
• | the costs, terms and availability of gathering, processing, fractionation and other midstream services; 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 exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the ability of the combined company to realize the anticipated benefits of the Business Combination, costs related to the Business Combination, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control overnon-operated properties, and the other risks described under “Risk Factors” in this prospectus.
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 reservoir engineers. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. 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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Issuance of Class A Common Stock Underlying Public Warrants
We will receive the proceeds from the exercise of Public Warrants, but not from the sale of the underlying shares of Class A Common Stock. Assuming the exercise of all of the Public Warrants at an exercise price of $11.50 per share, we expect to receive $396,750,000. We intend to use any proceeds for general corporate purposes.
Resale of Class A Common Stock by Selling Stockholders
We will not receive any of the proceeds from the sale of Class A Common Stock by the selling stockholders named herein. We will receive the proceeds from the exercise of Private Placement Warrants and the Forward Purchase Warrants, but not from the sale of the underlying shares of Class A Common Stock. Assuming the exercise of all of the Private Placement Warrants and the Forward Purchase Warrants at an exercise price of $11.50 per share (assuming no cashless exercise), we expect to receive $327,366,659. We intend to use any proceeds for general corporate purposes.
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DETERMINATION OF OFFERING PRICE
Issuance of Class A Common Stock Underlying Public Warrants
The offering price of the shares of Class A Common Stock underlying the Public Warrants offered hereby is determined by reference to the exercise price of the Public Warrants of $11.50 per share. The Public Warrants are listed on NASDAQ under the symbol “AMRWW.”
Resale of Class A Common Stock by Selling Stockholders
Our Class A Common Stock is listed on NASDAQ under the symbol “AMR.” The actual offering price by the selling stockholders of the shares of Class A Common Stock covered by this prospectus will be determined by prevailing market prices at the time of sale, by private transactions negotiated by the selling stockholders or as otherwise described in the section entitled “Plan of Distribution.”
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PRICE RANGE OF SECURITIES AND DIVIDENDS
Our Class A Common Stock and Public Warrants are currently listed on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Through February 9, 2018, our Class A Common Stock and Public Warrants were listed under the symbols “SRUN” and “SRUNW,” respectively.
The following table sets forth, for the calendar quarter indicated, the high and low sales prices per unit and share of Class A Common Stock as reported on NASDAQ, respectively, for the periods presented. Since warrants are not currently eligible to be exercised, there is no information presented for the warrants in the table below.
Units (SRUNU) | Class A Common Stock (AMR) | |||||||||||||||
High | Low | High | Low | |||||||||||||
Fiscal 2017: | ||||||||||||||||
Fourth Quarter | $ | 10.85 | $ | 10.25 | $ | 10.27 | $ | 9.75 | ||||||||
Third Quarter | $ | 10.76 | $ | 10.58 | $ | 10.23 | $ | 10.06 | ||||||||
Second Quarter(1) | $ | 10.80 | $ | 10.26 | $ | 10.23 | $ | 9.75 | ||||||||
First Quarter(2) | $ | 10.43 | $ | 10.40 | N/A | N/A |
(1) | Beginning on April 26, 2017 with respect to the Class A Common Stock. |
(2) | Beginning on March 29, 2017 with respect to the units. The Class A Common Stock and the warrants commenced separate trading on April 26, 2017. |
On February 12, 2018, the closing price of our Class A Common Stock and Public Warrants was $8.63 and $2.15, respectively. As of February 12, 2018, there were 169,371,730 shares of Class A Common Stock outstanding, held of record by one holder. In addition, 34,500,000 shares of Class A Common Stock are issuable upon exercise of the 34,500,000 Public Warrants, held of record by one holder. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares or Public Warrants through nominee names.
Dividend Policy
We have not paid any cash dividends on our Class A Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, we do not anticipate the board of directors declaring any dividends in the foreseeable future.
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SELECTED HISTORICAL FINANCIAL INFORMATION
The following table shows our selected historical financial information for the periods and as of the dates indicated. The selected historical consolidated financial information as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 was derived from the audited historical consolidated financial statements of Alta Mesa included elsewhere in this prospectus. The selected historical interim condensed consolidated financial information as of September 30, 2017 and for the nine months ended September 30, 2017 and 2016 was derived from the unaudited interim condensed consolidated financial statements of Alta Mesa included elsewhere in this prospectus. Historical financial information for Kingfisher is not included below and can be found in the financial statements attached to this prospectus.
Our historical results are not necessarily indicative of future operating results. In addition, the selected historical financial information below includes the results of operations from Alta Mesa’snon-STACK assets, which we did not acquire in the Business Combination. The selected consolidated and combined financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the historical consolidated and combined financial statements and accompanying notes included elsewhere in this prospectus.
Nine Months Ended September 30, | Year Ended December 31, | |||||||||||||||||||
2017 | 2016 | 2016 | 2015 | 2014 | ||||||||||||||||
(Unaudited) | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||
Operating Revenues and Other: | ||||||||||||||||||||
Oil | $ | 169,611 | $ | 115,778 | $ | 163,677 | $ | 199,799 | $ | 347,842 | ||||||||||
Natural gas | 37,780 | 20,277 | 30,953 | 30,621 | 65,002 | |||||||||||||||
Natural gas liquids | 22,814 | 10,109 | 15,663 | 10,864 | 18,281 | |||||||||||||||
Other revenues | 274 | 358 | 415 | 682 | 1,003 | |||||||||||||||
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Total operating revenues | 230,479 | 146,522 | 210,708 | 241,966 | 432,128 | |||||||||||||||
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Gain on sale of assets | — | 3,723 | 3,542 | 67,781 | 87,520 | |||||||||||||||
Gain on acquisition of oil and natural gas properties | 6,893 | — | — | — | — | |||||||||||||||
Gain (loss) on derivative contracts | 38,024 | (23,970 | ) | (40,460 | ) | 124,141 | 96,559 | |||||||||||||
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Total operating revenues and other | 275,396 | 126,275 | 173,790 | 433,888 | 616,207 | |||||||||||||||
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Operating expenses: | ||||||||||||||||||||
Lease and plant operating expense | 49,836 | 45,222 | 56,893 | 67,706 | 64,686 | |||||||||||||||
Marketing and transportation expense | 21,566 | 8,140 | 13,326 | 4,030 | 9,134 | |||||||||||||||
Production and ad valorem taxes | 8,812 | 8,021 | 10,750 | 15,131 | 28,214 | |||||||||||||||
Workover expense | 5,112 | 3,242 | 4,714 | 6,511 | 8,961 | |||||||||||||||
Exploration expense | 19,930 | 15,304 | 24,777 | 42,718 | 61,912 | |||||||||||||||
Depreciation, depletion, and amortization expense | 80,082 | 66,857 | 92,901 | 143,969 | 141,804 | |||||||||||||||
Impairment expense | 29,206 | 14,238 | 16,306 | 176,774 | 74,927 | |||||||||||||||
Accretion expense | 1,447 | 1,615 | 2,174 | 2,076 | 2,198 | |||||||||||||||
General and administrative expenses | 35,534 | 32,909 | 41,758 | 44,454 | 69,198 | |||||||||||||||
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|
|
|
|
|
|
|
|
| |||||||||||
Total operating expenses | 251,525 | 195,548 | 263,599 | 503,369 | 461,034 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Income (loss) from operations | 23,871 | (69,273 | ) | (89,809 | ) | (69,481 | ) | 155,173 | ||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest expense | (39,069 | ) | (52,253 | ) | (60,884 | ) | (62,473 | ) | (55,812 | ) | ||||||||||
Interest income | 880 | 672 | 894 | 723 | 15 | |||||||||||||||
Loss on extinguishment of debt | — | — | (18,151 | ) | — | — | ||||||||||||||
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|
|
|
|
|
|
|
| |||||||||||
Total other income (expense) | (38,189 | ) | (51,581 | ) | (78,141 | ) | (61,750 | ) | (55,797 | ) | ||||||||||
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| |||||||||||
Income (loss) before state income taxes | (14,318 | ) | (120,854 | ) | (167,950 | ) | (131,231 | ) | 99,376 | |||||||||||
Provision (benefit) for state income taxes | 285 | 107 | (29 | ) | 562 | 176 | ||||||||||||||
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|
|
|
|
|
|
| |||||||||||
Net income (loss) | $ | (14,603 | ) | $ | (120,961 | ) | $ | (167,921 | ) | $ | (131,793 | ) | $ | 99,200 | ||||||
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| |||||||||||
Cash Flow Data: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 55,516 | $ | 7,473 | $ | 131,376 | $ | 143,978 | $ | 184,884 | ||||||||||
Net cash used in investing activities | (301,059 | ) | (147,774 | ) | (224,298 | ) | (105,815 | ) | (189,721 | ) | ||||||||||
Net cash provided by (used in) financing activities | 242,098 | 139,636 | 91,238 | (30,643 | ) | (351 | ) | |||||||||||||
Other Supplementary Data: | ||||||||||||||||||||
Adjusted EBITDAX(1) | $ | 112,274 | $ | 133,499 | $ | 172,850 | $ | 211,806 | $ | 261,443 |
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September 30, | December 31, | |||||||||||||||
2017 | 2016 | 2015 | 2014 | |||||||||||||
(Unaudited) | ||||||||||||||||
(in thousands) | ||||||||||||||||
Balance Sheet Data: | ||||||||||||||||
Cash and cash equivalents | $ | 4,913 | $ | 7,618 | $ | 8,974 | $ | 25,142 | ||||||||
Other current assets | 81,945 | 58,624 | 114,095 | 139,254 | ||||||||||||
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| |||||||||
Total current assets | 86,858 | 66,242 | 123,069 | 164,396 | ||||||||||||
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| |||||||||
Total property and equipment, net | 954,006 | 721,893 | 537,039 | 697,681 | ||||||||||||
Other long-term assets | 43,032 | 25,716 | 62,417 | 49,048 | ||||||||||||
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| |||||||||
Total assets | $ | 1,083,896 | $ | 813,851 | $ | 722,525 | $ | 911,125 | ||||||||
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| |||||||||
Current liabilities | $ | 200,520 | $ | 152,403 | $ | 84,731 | $ | 118,696 | ||||||||
Revolving credit facility | 75,065 | 40,622 | 152,000 | 319,520 | ||||||||||||
Senior notes and Term Loan, net of unamortized deferred financing costs | 490,182 | 489,283 | 565,775 | 441,622 | ||||||||||||
Other long-term liabilities | 100,626 | 99,437 | 97,068 | 92,733 | ||||||||||||
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| |||||||||
Total liabilities | 866,393 | 781,745 | 899,574 | 972,571 | ||||||||||||
Owners’ equity | 217,503 | 32,106 | (177,049 | ) | (61,446 | ) | ||||||||||
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Total liabilities and owners’ equity | $ | 1,083,896 | $ | 813,851 | $ | 722,525 | $ | 911,125 | ||||||||
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(1) | Adjusted EBITDAX is anon-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see“—Non-GAAP Financial Measure” below. |
Non-GAAP Financial Measure
Adjusted EBITDAX is anon-GAAP financial measure and should not be considered as a substitute for net income (loss), operating income (loss) or any other performance measure derived in accordance with United States generally accepted accounting principles (“GAAP”) or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Our management believes Adjusted EBITDAX is useful because it allows external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods, hedging positions or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. We present Adjusted EBITDAX because we believe Adjusted EBITDAX is an important supplemental measure of our performance that is frequently used by others in evaluating companies in our industry. Because Adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDAX we present may not be comparable to similarly titled measures of other companies. We define Adjusted EBITDAX as net income (loss) before interest expense, loss on extinguishment of debt, exploration expense, depletion, depreciation and amortization, impairment expense, accretion expense, provision (benefit) for income taxes, (gain)/loss on sale of assets and (gain)/loss on derivative contracts.
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The following table presents a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.
Nine Months Ended September 30, | Year Ended December 31, | |||||||||||||||||||
2017 | 2016 | 2016 | 2015 | 2014 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Net income (loss) | $ | (14,603 | ) | $ | (120,961 | ) | $ | (167,921 | ) | $ | (131,793 | ) | $ | 99,200 | ||||||
Interest expense | 39,069 | 52,253 | 60,884 | 62,473 | 55,812 | |||||||||||||||
Loss on extinguishment of debt | — | — | 18,151 | — | — | |||||||||||||||
Exploration expense | 19,930 | 15,304 | 24,777 | 42,718 | 61,912 | |||||||||||||||
Depreciation, depletion and amortization | 80,082 | 66,857 | 92,901 | 143,969 | 141,804 | |||||||||||||||
Impairment expense | 29,206 | 14,238 | 16,306 | 176,774 | 74,927 | |||||||||||||||
Accretion expense | 1,447 | 1,615 | 2,174 | 2,076 | 2,198 | |||||||||||||||
Provision (benefit) for state income taxes | 285 | 107 | (29 | ) | 562 | 176 | ||||||||||||||
(Gain) on sale of asset | — | (3,723 | ) | (3,542 | ) | (67,781 | ) | (87,520 | ) | |||||||||||
(Gain) on acquisition of oil and natural gas properties | (6,893 | ) | — | — | — | — | ||||||||||||||
(Gain)/loss on derivative contracts(1) | (36,249 | ) | 107,809 | 129,149 | (17,192 | ) | (87,066 | ) | ||||||||||||
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Adjusted EBITDAX | $ | 112,274 | $ | 133,499 | $ | 172,850 | $ | 211,806 | $ | 261,443 | ||||||||||
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(1) | Net of cash settlements and which includes (i) $0.9 million and $58.4 million related to settlements of oil and natural gas derivative contracts prior to contract expiry for the nine months ended September 30, 2017 and 2016, respectively, and (ii) $64.0 million, $41.6 million and $0.3 million related to settlements of oil and natural gas derivative contracts prior to contract expiry for the years ended December 31, 2016, 2015 and 2014, respectively. |
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The following discussion of our business should be read in conjunction with the “Selected Historical Financial Information” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion includes information regarding Alta Mesa’snon-STACK assets, which were not acquired by us in the Business Combination.
The estimated proved reserve information for our properties as of December 31, 2016 and December 31, 2015 contained in this prospectus is based on reserve reports prepared by our internal engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineer (such reports being referred to as the “2016 Reserve Report” and “2015 Reserve Report” and, collectively, as the “Reserve Reports”). A copy of each of the Reserve Reports is attached to this prospectus as Exhibit B.
Corporate History
We were originally incorporated in Delaware on November 16, 2016 as a blank check company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses (an “initial business combination”). On November 21, 2016, our Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from us, for an aggregate purchase price of $25,000. On March 2017, we effected a stock dividend of 14,375,000 shares of Class B Common Stock, resulting in our Sponsor holding an aggregate of 25,875,000 founder shares. In March 2017, our Sponsor transferred 33,000 founder shares to each of our then independent directors (together with our Sponsor, the “initial stockholders”) at their original purchase price.
On March 29, 2017, we consummated our IPO of 103,500,000 Units (including 13,500,000 Units sold pursuant to the underwriters’ exercise of their over-allotment option) at $10.00 per Unit, with each Unit consisting of one share of Class A Common Stock andone-third of one Public Warrant. Simultaneously with the closing of our IPO on March 29, 2017, we completed the private sale of 15,133,333 warrants (the “Private Placement Warrants”) to our Sponsor at a purchase price of $1.50 per Private Placement Warrant, generating gross proceeds to us of $22,700,000. The Private Placement Warrants are identical to the Public Warrants, except that our Sponsor agreed not to transfer, assign or sell any of the Private Placement Warrants (except to certain permitted transferees) until 30 days after the completion of the Business Combination. The Private Placement Warrants are also not redeemable by us so long as they are held by our Sponsor or its permitted transferees.
A total of $1.035 billion (including approximately $36.2 million in deferred underwriting commissions to the underwriters of the IPO), which represents $1.0143 billion of the proceeds from the IPO after deducting upfront underwriting commissions of $20.7 million, and the proceeds of the sale of the private placement warrants were placed in the Trust Account (the “Trust Account”) to be used to fund an initial business combination. On April 26, 2017, we announced that the holders of our Units could elect to separately trade the Class A Common Stock and Public Warrants included in the Units.
From the consummation of our IPO through the end of July, 2017, we were searching for a suitable target business to effect an initial business combination. On August 16, 2017, we entered into the following agreements:
• | the Contribution Agreement, dated as of August 16, 2017 (the “Alta Mesa Contribution Agreement”), among High Mesa Holdings, LP (the “Alta Mesa Contributor”), High Mesa Holdings GP, LLC, the sole general partner of the Alta Mesa Contributor, Alta Mesa Holdings, LP (“Alta Mesa”), Alta Mesa Holdings GP, LLC, the sole general partner of Alta Mesa (“Alta Mesa GP”), us and the equity owners of the Alta Mesa Contributor, |
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• | the Contribution Agreement, dated as of August 16, 2017 (the “Kingfisher Contribution Agreement”), among KFM Holdco, LLC (the “Kingfisher Contributor”), Kingfisher Midstream, LLC (“Kingfisher”), us and the equity owners of the Kingfisher Contributor; and |
• | the Contribution Agreement, dated as of August 16, 2017 (the “Riverstone Contribution Agreement” and, together with the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, the “Contribution Agreements”), between Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor” and, together with the Alta Mesa Contributor and the Kingfisher Contributor, the “Contributors”), and us. |
On February 9, 2018 (the “Closing Date”), we consummated the acquisition of (i) all of the limited partnership interests in Alta Mesa, (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP and (iii) all of the membership interests in Kingfisher (such acquisition, the “Business Combination”).
At the closing of the Business Combination (the “Closing”),
• | we issued 40,000,000 shares of Class A Common Stock and warrants to purchase 13,333,333 shares of Class A Common Stock to Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”) pursuant to the terms of that certain Forward Purchase Agreement, dated as of March 17, 2017 (the “Forward Purchase Agreement”) for cash proceeds of $400.0 million to us; |
• | we contributed $1,406.4 million in cash (the proceeds of the Forward Purchase Agreement and the net proceeds (after redemptions) of the Trust Account) to SRII Opco, LP, a Delaware limited partnership (“SRII Opco”), in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests (the “SRII Opco Common Units”) in SRII Opco issued to us and (ii) 62,966,666 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”) issued to us; |
• | we caused SRII Opco to issue 213,402,398 SRII Opco Common Units (approximately 55.8%) to the Contributors in exchange for the ownership interests in Alta Mesa, Alta Mesa GP and Kingfisher contributed to SRII Opco by the Contributors; |
• | we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to the Alta Mesa Contributor and the Kingfisher Contributor if theearn-out consideration provided for in the Contribution Agreements is earned by the Alta Mesa Contributor or the Kingfisher Contributor pursuant to the terms of the Contribution Agreements; |
• | we issued to each of the Contributors a number of shares of Class C common stock, par value $0.0001 per share (the “Class C Common Stock”) equal to the number of the SRII Opco Common Units received by such Contributor at the Closing; |
• | SRII Opco distributed to the Kingfisher Contributor cash in the amount of approximately $814.8 million in partial payment for the ownership interests in Kingfisher contributed by the Kingfisher Contributor; and |
• | SRII Opco entered into a voting agreement with the owners of the remaining 10% voting interests in Alta Mesa GP whereby such other owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco. |
Holders of Class C Common Stock, together with holders of Class A Common Stock, voting as a single class, will have the right to vote on all matters properly submitted to a vote of the stockholders, but holders of Class C Common Stock will not be entitled to any dividends or liquidating distributions from us. After a specified period of time after Closing, the Contributors will generally have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash; provided that we may, at our option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.
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In connection with the Closing, we also issued (i) one share of Series A Preferred Stock, par value $0.0001 per share (“Series A Preferred Stock”), to each of Bayou City Energy Management, LLC (“Bayou City”), HPS Investment Partners, LLC (“HPS”), and AM Equity Holdings, LP (“AM Management”), and (ii) one share of Series B Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), to the Riverstone Contributor. None of the holders of the Series A Preferred Stock or Series B Preferred Stock is entitled to any dividends from us related to such Preferred Stock, but such holders are entitled to preferred distributions in liquidation in the amount of $0.0001 per share of Preferred Stock, and will have limited voting rights as described below. Shares of the Preferred Stock are redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Preferred Stock at the election of the holder thereof or (3) upon a breach by the holder of the transfer restrictions applicable to such Preferred Stock. For so long as the Series A Preferred Stock or Series B Preferred Stock remains outstanding, as applicable, the holders thereof are entitled to nominate and elect directors to our board of directors for a period of up to five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock.
Pursuant to the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, for a period of seven years following the Closing, the Alta Mesa Contributor and the Kingfisher Contributor may be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) asearn-out consideration if the20-Day VWAP of the Class A Common Stock equals or exceeds specified prices as follows (each such payment, an“Earn-Out Payment”):
20-Day VWAP | Earn-Out Consideration Payable to Alta Mesa Contributor | Earn-Out Consideration Payable to Kingfisher Contributor | ||||
$14.00 | 10,714,285 SRII Opco Common Units | 7,142,857 SRII Opco Common Units | ||||
$16.00 | 9,375,000 SRII Opco Common Units | 6,250,000 SRII Opco Common Units | ||||
$18.00 | 13,888,889 SRII Opco Common Units | — | ||||
$20.00 | 12,500,000 SRII Opco Common Units | — |
Neither the Alta Mesa Contributor nor the Kingfisher Contributor will be entitled to receive a particularEarn-Out Payment on more than one occasion and, if, on a particular date, the20-Day VWAP entitles the Alta Mesa Contributor or the Kingfisher Contributor to more than oneEarn-Out Payment (each of which has not been previously paid), the Alta Mesa Contributor and/or the Kingfisher Contributor will be entitled to receive each suchEarn-Out Payment. The Alta Mesa Contributor and the Kingfisher Contributor will be entitled to theearn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified20-Day VWAP hurdles.
On February 6, 2018, our stockholders voted to approve the Business Combination. In connection with that vote, the holders of shares of Class A Common Stock originally sold as part of the units issued in our IPO (such holders, the “public stockholders”), were provided with the opportunity to redeem shares of Class A Common Stock then held by them for cash equal to approximately $10.00 per share. Public holders of 3,270 shares of Class A Common Stock elected to redeem those shares and, at the Closing, $32,944 held in the Trust Account was paid to such redeeming shareholders and the remaining $1,042.7 million held in the Trust Account was disbursed to us. We used these funds, along with the proceeds of the Forward Purchase Agreement, to fund our obligations under the Contribution Agreements and to pay the underwriters’ deferred discount.
On February 9, 2018, all of the outstanding founder shares were automatically converted into shares of Class A Common Stock on aone-for-one basis in connection with the Closing.
Following the Business Combination, we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” and continued the listing of our Class A Common Stock and Public Warrants on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Following the completion of the Business Combination, the size of our board of directors was expanded from four directors to 11, including one director
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appointed by Bayou City and its affiliates, one director appointed by HPS and its affiliates and two directors appointed by AM Management and its affiliates, as the holders of our Series A Preferred Stock, and three directors appointed by the Riverstone Contributor and its affiliates, as the holder of our Series B Preferred Stock. In addition, in connection with the Business Combination, we appointed the management team of Alta Mesa to hold most of our executive officer positions.
Alta Mesa is considered our accounting predecessor and hence the historical financial statements of Alta Mesa for the three years ended December 31, 2016 and the interim period ended September 30, 2017 (unaudited) are included elsewhere in this prospectus. The (a) historical financial statements of Silver Run Acquisition Corporation II for the period from November 16, 2016 (date of inception) to December 31, 2016 and for the nine months ended September 30, 2017 (unaudited), (b) historical financial statements of Kingfisher for the year ended December 31, 2016 and the period from inception (January 30, 2015) through December 31, 2015, and for the nine months ended September 30, 2017 (unaudited), and (c) the unaudited pro forma condensed, consolidated, combined balance sheet of Silver Run Acquisition Corporation II at September 30, 2017, and unaudited pro forma condensed, consolidated, combined statements of operations for the year ended December 31, 2016 and the nine months ended September 30, 2017 are included only as Exhibits to this prospectus.
Business Overview
Following the Business Combination, our only significant asset is our ownership of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa (which owns our E&P Business) and Kingfisher (which owns our Midstream Business). Founded in 1987, Alta Mesa is an exploration and production company focused on the development and acquisition of unconventional oil and natural gas reserves in the eastern portion of the Anadarko Basin referred to as the STACK. The STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates. As of September 30, 2017, we had assembled a highly contiguous position of approximately 130,000 net acres largely in theup-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. As of December 31, 2016, we had 4,196 identified gross horizontal drilling locations, 2,075 of which we expect to operate. These drilling locations are in our primary target formations comprised of the Osage, Meramec and Oswego. We continue to opportunistically acquire acreage in ournon-operated locations with the goal of operating wells in these locations. As of September 30, 2017, we were operating six horizontal drilling rigs in the STACK with plans to continue to operate that number of rigs through the end of 2017.
Our Midstream Business primarily focuses on providing crude oil gathering, gas gathering and processing and marketing to producers of natural gas, NGLs, crude oil and condensate in the STACK play. Our midstream energy asset network includes approximately 308 miles of existing low and high pressure pipelines, a 60 MMcf/d cryogenic natural gas processing plant, 10 MMcf/d in offtake processing, compression facilities, crude storage, NGL storage and purchasing and marketing capabilities.
Our goal is to build a premier development and acquisition company focused on horizontal drilling and gas gathering in the STACK.
OUR E&P BUSINESS
We intend to grow our reserves and production through the development of our multi-year inventory of identified drilling locations within the STACK. As of December 31, 2016, we had drilled and completed 112 gross (98.3 net) horizontal wells in the STACK and participated in an additional 70 gross (11.9 net) horizontal wells in the STACK. From 2013 to September 30, 2017, we increased our STACK production at a compound
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annual growth rate (“CAGR”) of approximately 82%. We increased our leasehold interests from approximately 45,000 net acres in early 2015 to approximately 130,000 net acres as of September 30, 2017 primarily through the acquisition of largely undeveloped leasehold. We had average daily net production in the STACK of approximately 22,300 BOE/d for the month of October 2017 (69% liquids).
Beginning in the early 1990s, our STACK operations were focused on vertical wells, waterfloods and analyzing the commercial productivity of the stacked formations on our acreage. Since late 2012, however, we have concentrated on the horizontal development of theMississippian-age Osage and Meramec formations, as well as thePennsylvanian-age Oswego formation. We intend to expand this activity with horizontal wells to further develop other formations with demonstrated vertical production, including thePennsylvanian-age Big Lime, Prue, Skinner, Red Fork and Cherokee Shale;Mississippian-age Manning Lime;Devonian-age Woodford Shale; andSilurian-age Hunton Lime formations.
We consider our operations in the STACK to be in the early phase of a systematic, long-term development program. Our initial focus has been to delineate the Osage, Meramec and Oswego formations through the drilling of horizontal wells in 10 contiguous townships in Kingfisher County, Oklahoma and one adjacent township in Garfield County, Oklahoma. We have commenced infill development with seven multi-well patterns of three to 10 wells each, given that we expect full development of our leasehold to require multiple wells per drilling unit to maximize economic recovery of oil and natural gas from each formation.
Our NYMEX net proved reserves in the STACK as of December 31, 2016 were 143.6 MMBOE, representing a 110% increase over 2015year-end net proved reserves of 68.3 MMBOE. Our 2015year-end net proved reserves represent a 147% increase over 2014year-end net proved reserves of 27.6 MMBOE. The increase in net proved reserves has primarily been driven by continued development of our properties and acquired assets that we subsequently drilled and converted into proved reserves in the STACK.
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The following charts illustrate our net proved reserves and production growth in the STACK for the periods indicated.
Net Proved Reserves and Production Growth
SEC Net Proved Reserves
NYMEX Net Proved Reserves
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Net Daily Production(1)
(1) | Production data and the CAGR for the year ended December 31, 2016 include 24 producing wells purchased by High Mesa Inc. and contributed to us on December 31, 2016. See “—Bayou City Joint Development Agreement” below. |
(2) | Gross operated production continued to growyear-to-date from the second quarter of 2017 to the third quarter of 2017. Net production remained relatively consistent between the second and third quarters of 2017, reflecting a higher proportion of wells drilled in 2017 under our joint development agreement with BCE. As of early November 2017, we had drilled or completed 53 wells of a total of 80 contemplated under the joint development agreement with BCE, and expect to drill the remainder of these by the end of 2018. As provided under the joint development agreement, we give a proportionate 80% working interest in the well bores to BCE in return for BCE funding a proportionate 100% of the drilling and completion costs. BCE’s working interest will be reduced and our proportionate working interest will increase upon BCE reaching certain internal rates of return on the wells. |
(3) | STACK production CAGR from 2013 to September 30, 2017. |
Reserves and Inventory Details
The information with respect to our reserves has been prepared in accordance with the rules and regulations of the SEC, except with respect to the table, which provides our reserves based on NYMEX forward strip prices for oil and natural gas as explained below. Our proved reserves as of December 31, 2016 are estimates only and are based on reserve reports prepared by our internal engineers and audited by our independent petroleum engineer.
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SEC Pricing
The following table contains our STACK SEC net proved reserves as of December 31, 2016 and net acreage and production as of and for the nine months ended September 30, 2017.
SEC Proved Reserves (MMBOE) (1) | SEC Pricing PV-10 ($ Millions) (1) | SEC Pricing % Proved Developed (2) | SEC Pricing Liquids% of Total Proved Reserves (2) | Net Acreage (3) | Net Producing Wells (4) | Average Daily Net Production (MBOE/d) | ||||||||||||||||||||||
STACK (Horizontal) | 126.6 | $ | 521.7 | 23.8 | % | 61.9 | % | 127,424 | 108.8 | 18.9 | ||||||||||||||||||
STACK (Vertical) | 3.0 | $ | 12.8 | 99.6 | % | 71.1 | % | — | 230.1 | 1.2 | ||||||||||||||||||
Total | 129.6 | $ | 534.5 | 25.6 | % | 62.2 | % | 127,424 | 338.9 | 20.1 |
(1) | SEC total proved reserves andPV-10 were calculated using SEC definitions and oil and natural gas price parameters established by current SEC guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended December 31, 2016. Because Alta Mesa is a partnership and was not subject to federal income taxes, our SECPV-10, as of December 31, 2016 is the same as our standardized measure of future net cash flows, the most comparable measure under GAAP, which is reduced for the discounted value of estimated future income taxes. Therefore, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to Alta Mesa’s equity holders. However, we are a corporation subject to federal income tax and our future income taxes will be dependent upon our future taxable income. We estimate that the pro forma standardized measure as of December 31, 2016 would have been approximately $442.8 million, as adjusted to give effect to the present value of approximately $91.7 million of future income taxes as a result of being treated as a corporation for federal income tax purposes. Calculation of SECPV-10 does not give effect to derivatives transactions. The unweighted arithmetic average prices as of the first of each month during the 12 months ended December 31, 2016 were $42.75 per Bbl of oil and $2.49 per MMBtu of natural gas. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. |
(2) | Computed as a percentage of total reserves of the area. |
(3) | Includes developed and undeveloped acreage. |
(4) | Net producing wells are as of December 31, 2016 and exclude 9.9 DUC wells (9.8 operated, 0.1non-operated). |
NYMEX Pricing
The following table contains our STACK NYMEX net proved reserves as of December 31, 2016 using NYMEX strip prices as of December 31, 2016 (as that date was our year end and the date on which most key assumptions were settled on with respect to 2016 reserve estimation).
NYMEX Proved Reserves (MMBOE) (1) | NYMEX Pricing PV-10 ($ Millions) (1) | NYMEX % Proved Developed (2) | NYMEX Liquids% of Total Proved Reserves (2) | |||||||||||||
STACK (Horizontal) | 139.8 | $ | 1,172.4 | 24.2 | % | 61.1 | % | |||||||||
STACK (Vertical) | 3.8 | $ | 26.8 | 99.4 | % | 72.3 | % | |||||||||
Total | 143.6 | $ | 1,199.2 | 26.1 | % | 61.4 | % |
(1) | Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural |
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gas on December 31, 2016 rather than using the average of thefirst-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The “NYMEX Pricing” proved reserves were calculated using the following prices for oil and natural gas based on average annual NYMEX forward-month contract pricing in effect on December 31, 2016 to better reflect the market expectations as of that date. For December 31, 2016, the assumed oil price was $56.20 per Bbl in 2017, $56.59 per Bbl in 2018, $56.10 per Bbl in 2019, $56.05 per Bbl in 2020, $56.21 per Bbl in 2021 and $56.51 per Bbl held constant thereafter and the assumed natural gas prices were $3.61 per MMBtu in 2017, $3.14 per MMBtu in 2018, $2.87 per MMBtu in 2019, $2.88 per MMBtu in 2020 and $2.91 per MMBtu in 2021 and $2.93 per MMBtu held constant thereafter. Pricing was adjusted for basis differentials by field based on our historical realized prices. The NYMEX Strip Price Proved Reserves are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with “SEC Pricing” Proved Reserves as outlined above and do not comply with SEC pricing assumptions. Ryder Scott audited our reserves at December 31, 2016 in a reserves audit. |
(2) | Computed as a percentage of total reserves of the area. |
We believe that the presentation of reserve volumes using NYMEX forward strip pricing is informative as they are presented based upon the prices at which the marketplace believes oil and gas will be sold in the future. The price at which we can sell our production in the future is the major determinant of the likely economic producibility of our reserves. We hedge substantial amounts of future production based upon futures prices. In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. Our lenders also make borrowing base determinations based upon forward strip pricing.
While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate. Actual future prices may vary significantly from the NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed. See “Risk Factors—Risks Related to the E&P Business—Oil and natural gas prices are highly volatile and depressed prices can significantly and adversely affect our financial condition and results of operations,” “Risk Factors—Risks Related to the E&P Business—Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves,” and “Risk Factors—Risks Related to the E&P Business—The present value of future net revenues from our proved reserves or“PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves” for more information regarding the uncertainty associated with price and reserve estimates.
Drilling Locations
We have a significant multi-year drilling inventory across a number of historically productive formations in the STACK. The table below sets forth the gross horizontal drilling locations that we have identified on our leasehold in our primary target formations and our estimate of additional prospective gross horizontal drilling locations on our leasehold that we have identified, either under downspacing or targeting formations that we have not yet developed with horizontal drilling. However, based upon the results of our drilling program and those of other offset operators, we believe significant development opportunities exist in these prospective target formations. See “—Our Horizontal Drilling Locations” for a more detailed description of our methodology in determining our identified and prospective horizontal drilling locations.
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Gross Horizontal Drilling Locations in the STACK by Targeted Formations(1)
Identified Drilling Locations | Prospective Drilling Locations | Combined | ||||||||||||||||||||||||||
Locations (2)(3) | Average Working Interest (%) | Other Formations Locations (4) | Downspacing Locations (5) | Total Locations | Average Working Interest (Including Downspacing Locations) (%) | Total Locations | ||||||||||||||||||||||
Operated(6): | ||||||||||||||||||||||||||||
Osage | 1,196 | 72 | % | — | 1,141 | 1,141 | 73 | % | 2,337 | |||||||||||||||||||
Meramec | 676 | 74 | % | — | 676 | 676 | 74 | % | 1,352 | |||||||||||||||||||
Oswego | 203 | 75 | % | — | 206 | 206 | 81 | % | 409 | |||||||||||||||||||
Manning | — | — | 168 | — | 168 | 75 | % | 168 | ||||||||||||||||||||
Other Formations | — | — | 1,327 | — | 1,327 | 70 | % | 1,327 | ||||||||||||||||||||
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Total Operated: | 2,075 | 73 | % | 1,495 | 2,023 | 3,518 | 73 | % | 5,593 | |||||||||||||||||||
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Drilling Inventory (Years)(7) | 14.4 | — | 10.4 | 14.0 | 24.4 | — | 38.8 | |||||||||||||||||||||
Other(6): | ||||||||||||||||||||||||||||
Osage . | 1,252 | 15 | % | — | 1,113 | 1,113 | 15 | % | 2,365 | |||||||||||||||||||
Meramec | 588 | 15 | % | — | 596 | 596 | 15 | % | 1,184 | |||||||||||||||||||
Oswego | 281 | 13 | % | — | 310 | 310 | 14 | % | 591 | |||||||||||||||||||
Manning | — | — | 316 | — | 316 | 14 | % | 316 | ||||||||||||||||||||
Other Formations | — | — | 2,084 | — | 2,084 | 55 | % | 2,084 | ||||||||||||||||||||
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Total Other: | 2,121 | 15 | % | 2,400 | 2,019 | 4,419 | 28 | % | 6,540 | |||||||||||||||||||
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Total Gross Locations | 4,196 | 3,895 | 4,042 | 7,937 | 12,133 | |||||||||||||||||||||||
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(1) | Lateral lengths are assumed to be 4,800 to 5,000 feet depending upon formation. For a description of our methodology used in identifying our identified drilling locations and estimating the number of additional prospective drilling locations, see “—Our Horizontal Drilling Locations.” We may not drill all of these identified or prospective horizontal drilling locations. See “Risk Factors—Risks Related to the E&P Business—Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.” |
(2) | Includes 272 locations attributed to proved undeveloped reserves in our 2016 Reserve Report, all of which target the Osage formation. |
(3) | Assumes the following number of wells per 640 acre section that may be drilled in the following formations based on current regulations: Oswego—2; Meramec—4; Lower Osage—4; and Upper Osage—4. |
(4) | Assumes the following number of wells per 640 acre section that may be drilled in the following formations based on current regulations: Big Lime—4; Cherokee—4; Manning—4; Chester—8; Woodford—8; and Hunton—1. |
(5) | Assumes drilling based upon a regulatory change to permit an increase in the number of total wells per 640 acre section that may be drilled in the following formations: Oswego—4; Meramec—8; Lower Osage—8; and Upper Osage—7. There is no assurance that Oklahoma regulations will be revised to permit downspacing or that downspacing will prove economic in providing larger ultimate recoveries from a section. Downspacing may reduce per well EURs due to potential cross drainage. Certain of these locations are subject to participation in our joint development agreement. See “—Bayou City Joint Development Agreement” below. |
(6) | Operatorship is not yet determined for many of our locations. Based on our experience, we are likely to become the operator if we have more than 240 leased acres in a640-acre section. As of December 31, 2016, we have 2,075 identified gross horizontal locations and 3,518 prospective gross drilling locations which we classify as operated located in sections where we have leased greater than 240 acres. Additionally, we have |
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2,121 identified gross horizontal locations and 4,419 prospective gross drilling locations which we classify as other located in sections where we have leased fewer than 240 acres. However, we may ultimately operate in sections with fewer than 240 acres leased and may not operate in sections with more than 240 acres leased. |
(7) | Years of drilling inventory is calculated assuming total gross operated wells, drilling time of 15 days per well (24 wells per year, per rig) and six concurrently operating rigs, which is the current number of rigs we are operating in the STACK. This is shown for illustrative purposes. We will not necessarily drill our entire inventory. Our STACK rig count may increase or decrease in the future depending on numerous factors, including changes in oil and natural gas prices, drilling costs, rig availability, drilling results, our working interest in the location, offtake and water disposal and capital budget decisions. |
Market Access
We have favorable access to physical markets for our crude oil, natural gas and natural gas liquids produced from our STACK leasehold. Our operations are located less than 60 miles from the principal North American hub for crude oil in Cushing, Oklahoma, providing access to regional and national refining and petrochemical markets.
We are also served by pipelines transporting natural gas liquids to processing centers and market hubs in Kansas and the Gulf Coast region. Numerous natural gas gathering systems and associated processing facilities have been in operation in proximity to our STACK assets for several decades and midstream companies have recently installed more robust gathering infrastructure and modern gas processing facilities to support increasing production volumes in the area. We sell a portion of our natural gas to legacy gas processors, including DCP, Mustang, EnLink, MarkWest and Energy Transfer.
In the second quarter of 2016, we commissioned a 60 MMcf/d cryogenic gas processing facility within our acreage footprint. This facility receives natural gas from our gathering system, which (i) is designed to accommodate the anticipated larger volumes we expect to produce from multi-well pads and (ii) offers assurance of processing and residue capacity to support future production growth. We have commenced a 200 MMcf/d expansion that we expect to be operational in the first quarter of 2018.
We have committed the oil and natural gas production from our Kingfisher County, Oklahoma acreage, not otherwise committed to others, to our Midstream Business. Beginning June 1, 2018, our subsidiary, Oklahoma Energy Acquisitions, LP, will have residue natural gas firm transport along the ONEOK Gas Transmission pipeline for 100,000 Dth/d.
Bayou City Joint Development Agreement
In January 2016, we entered into a joint development agreement with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. The drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of September 30, 2017, 43 additional joint wells have been drilled or spudded leaving 37 joint wells to be drilled under the joint development agreement. Of the approximately 113 gross wells we plan to drill in 2017, approximately 35 are expected to be drilled under the joint development agreement.
Under the joint development agreement, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding this limit. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest (the “BCE Interest”) in each wellbore, which BCE Interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of
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return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear their respective proportionate working interest share of all subsequent costs and expenses related to such joint well.
Our Horizontal Drilling Locations
We have a significant multi-year drilling inventory within a number of pay zones in our STACK acreage. We have estimated our drilling locations by drilling unit, reservoir, and benches within each reservoir based on pay thickness, volumetric analyses, and production results. The production results include decades of vertical well performance in and around our acreage, horizontal wells we have drilled and completed since late 2012, as well as production from multi-well spacing tests we have conducted across our acreage. We have made these assumptions for the drilling units in which we operate and for those we do not operate. As of December 31, 2016, we have an inventory of 3,712 gross (1,636 net) identified horizontal drilling locations to develop the Osage and Meramec formations and 484 gross (190 net) identified horizontal drilling locations to develop the Oswego formation in our STACK position of approximately 100,000 net acres. Included within our total identified drilling locations are 272 locations associated with proved undeveloped reserves as of December 31, 2016.
Our identified horizontal development location count implies approximately 1,320 foot spacing between wells in the Osage formation, approximately 1,320 foot spacing between wells in the Meramec formation, and 2,640 foot spacing in the Oswego formation. The lateral length of our horizontal drilling locations is between 4,800 and 5,200 feet. In addition to these identified horizontal drilling locations, we believe we have the potential to increase our multi-year drilling inventory through horizontal downspacing in the Osage, Meramec, and Oswego formations and from additional horizontal locations in the Big Lime, Cherokee, and Manning, Chester, Woodford, and Hunton formations.
Our near-term development plan focuses on continued optimization of well spacing, frac stage spacing, transitioning to development mode, delineating Oswego and Manning horizons, and accelerating infrastructure investments. All of the wells in our inventory are planned as single-section laterals, and we plan to focus primarily on pattern development during 2017.
The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. See “Risk Factors—Risks Related to the E&P 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.”
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STACK Horizontal Wells History
We have increased our drilling activity in the STACK, from 10 wells in 2013 to 29 wells in 2014, 28 wells in 2015 and 72 wells in 2016. Through September 30, 2017, we have drilled 220 wells and have completed 169 gross (125 net) horizontal wells classified as proved developed producing reserves in the Osage and Meramec formations, of which 30 gross wells were funded through our development agreement. The following table sets forth our horizontal wells history in the STACK as of December 31, 2016.
Well Name | Well Count (No.) (1)(2) | Lateral (“Lt.”) Length (Feet) | EUR (MBO) | EUR (MMCF) | EUR (MBOE) (3) | EUR/ Lt. Foot (MBOE/ 1,000’) | EUR% Oil | 90 Day Cum (MBOE) | 90 Day Cum / Lt. Foot (MBOE/ 1,000’) | 90 Day Cum % Oil | D&C ($MM) | D&C/ Lt. Foot ($/Lt. Foot) | ||||||||||||||||||||||||||||||||||||
Average Generation 1 | 7 | 4,224 | 71 | 395 | 149 | 35 | 56 | % | 11,709 | 2,820 | 74 | % | $ | 4.1 | $ | 974 | ||||||||||||||||||||||||||||||||
Average Generation 1.5 | 6 | 4,656 | 183 | 1,485 | 472 | 104 | 43 | % | 28,220 | 6,276 | 77 | % | $ | 4.5 | $ | 968 | ||||||||||||||||||||||||||||||||
Average Generation 2.0 | 30 | 4,443 | 234 | 1,589 | 543 | 121 | 45 | % | 27,231 | 6,077 | 79 | % | $ | 4.3 | $ | 990 | ||||||||||||||||||||||||||||||||
Average Generation 2.0 | 20 | 4,781 | 266 | 1,927 | 682 | 142 | 40 | % | 24,546 | 5,115 | 79 | % | $ | 3.3 | $ | 681 | ||||||||||||||||||||||||||||||||
Average Generation 2.0 | 50 | 4,578 | 247 | 1,724 | 598 | 130 | 43 | % | 26,157 | 5,693 | 79 | % | $ | 3.9 | $ | 866 | ||||||||||||||||||||||||||||||||
Average Generation 2.5 | 6 | 4,920 | 239 | 1,094 | 452 | 93 | 63 | % | 18,732 | 3,719 | 90 | % | $ | 3.6 | $ | 726 | ||||||||||||||||||||||||||||||||
Average Generation 2.5 | 29 | 4,735 | 262 | 1,638 | 615 | 130 | 43 | % | 29,113 | 6,095 | 76 | % | $ | 3.6 | $ | 754 | ||||||||||||||||||||||||||||||||
Average Generation 2.5 | 35 | 4,766 | 258 | 1,545 | 587 | 123 | 46 | % | 27,516 | 5,730 | 78 | % | $ | 3.6 | $ | 749 | ||||||||||||||||||||||||||||||||
Average Alta Mesa Legacy | 49 | 4,496 | 205 | 1,345 | 467 | 103 | 49 | % | 24,322 | 5,417 | 79 | % | $ | 4.2 | $ | 953 | ||||||||||||||||||||||||||||||||
Average Alta Mesa Modern | 49 | 4,754 | 264 | 1,756 | 642 | 135 | 42 | % | 26,938 | 5,629 | 77 | % | $ | 3.4 | $ | 724 | ||||||||||||||||||||||||||||||||
Average Alta Mesa Well: | 98 | 4,625 | 234 | 1,551 | 554 | 119 | 45 | % | 25,556 | 5,517 | 78 | % | $ | 3.8 | $ | 838 | ||||||||||||||||||||||||||||||||
Average Generation 2.0 and | 85 | 4,656 | 251 | 1,650 | 594 | 127 | 44 | % | 26,622 | 5,705 | 79 | % | $ | 3.8 | $ | 818 |
(1) | The number of wells excludes four wells in the Oswego and Woodford formations as of December 31, 2016. |
(2) | Based on the 2016 Reserve Report. Excludes 10 wells with circumstances that will not be repeated due to unacceptable results: (i) four wells with very tight spacing (i.e. 660 feet in a high porosity area), (ii) three child wells drilled between two parent wells without injecting water into the parent wells prior to frac, (iii) two wells which were shut in for more than 90 days after frac and (iv) one well that fraced into a vertical well and the vertical well was not plugged in the Osage and Meramec formations. The average audited EUR for these wells is 221 MBOE per well. |
(3) | As used in this prospectus, EURs per well represent the sum of total gross remaining proved reserves per well as of December 31, 2016 (SEC pricing) plus cumulative production prior to such date for developed wells. EURs of horizontal wells will vary depending upon many factors, including, without limitation, lateral lengths, spacing and number of fracing stages, and quality of the penetrated formation. These EURs are not intended to be representative of anticipated future results of all wells drilled on our STACK acreage. |
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Completion Summary by Generation
We have proactively modified our completion designs with each generation, which has led to improved well response and overall economics, including: (i) the number of stages increasing with each generation as stage spacing decreases, (ii) average sand per stage increasing with each generation, (iii) total fluid per stage increasing with each generation, and (iv) changes in completion hardware.
Design Parameters | Generation 1.0 | Generation 1.5 | Generation 2.0 | Generation 2.5 | ||||
Average Frac Stages | 12 | 18 | 24 | 32 | ||||
Average Stage Spacing (Ft.) | 340 | 256 | 194 | 147 | ||||
Slickwater—Average Total (Bbls/Ft.) | 29 | 40 | 56 | 64 | ||||
Sand—Total Average (Lbs/Ft.) | 317 | 457 | 677 | 1,234 | ||||
Frac Design Type | Packer/Sleeve | Hybrid | Plug/Perf | Plug/Perf | ||||
Flow Design Type | Slickwater | Slickwater | Slickwater | Slickwater | ||||
Packers Type | Mechanical | Mechanical | Swell | Swell | ||||
Well Count(1) | 7 | 6 | 59 | 108 |
(1) | Wells completed as of September 30, 2017. |
Oil-Weighting Over Time
The well illustrated below is a representative PUD from the 2016 Reserve Report and is considered to be a typical well in terms of rates, declines, and production ratios. The following provides a description of the well’stwo-stream production and three-stream production in terms of oil and liquids content, respectively. In month one,two-stream production from the well is 82% oil and three-stream production is 86% liquids. In year one,two-stream production from the well is 66% oil and three-stream production is 74% liquids. The well breaches thetwo-stream 50% oil point near the end of year two and the three-stream production remains above 50% liquids point for the life of the well. Approximately 57% of the oil, 50% of the natural gas liquids and 38% of the natural gas are produced in the first five years thereby enhancing the early revenue per unit and the resulting economics. The gas to oil ratio (GOR) increases over time with month one approximately 1 Mcf per Bbl, month 12 approximately 5 Mcf per Bbl, and month 60 approximately 8 Mcf per Bbl.
Oil and Liquids Over Time(1)
(1) | LNU17N06W02A Miss well (from the 2016 Reserve Report). |
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Capital Expenditures
We anticipate a capital budget for STACK assets for 2017 of $360.0 million comprised of $216.0 million for drilling and completion, $89.0 million for leasehold and acquisitions, and $55.0 million for facilities, midstream and other expenditures. For the nine months ended September 30, 2017, we have been funded approximately $92.7 million from BCE under the joint development agreement. With total expected 2017 capital expenditures of $453.0 million, we expect to maintain 6 rigs through the end of 2017 which will result in drilling 113.0 gross wells targeting the Osage, Meramec, Oswego and Manning formations. Our 2017 capital expenditure budget is subject to change based on various market conditions, including changes in commodities prices and drilling costs.
In connection with the Riverstone Contribution Agreement, the Riverstone Contributor made a $200.0 million capital contribution to Alta Mesa in exchange for limited partner interests in Alta Mesa. Alta Mesa may use such capital to fund our capital expenditures prior to the Closing.
Our Oil and Natural Gas Reserves
The table below summarizes our estimated net SEC proved reserves (which includesnon-STACK assets) and for our STACK assets, as of December 31, 2016:
The Company | STACK Assets | |||||||||||||||
Oil and Natural Gas Liquids (MBbls) | Gas (MMcf) | Oil and Natural Gas Liquids (MBbls) | Gas (MMcf) | |||||||||||||
Proved Reserves(1) | ||||||||||||||||
Developed | 24,809 | 93,361 | 20,951 | 72,951 | ||||||||||||
Undeveloped | 61,280 | 222,644 | 59,589 | 221,308 | ||||||||||||
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Total Proved | 86,089 | 316,005 | 80,540 | 294,259 | ||||||||||||
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(1) | Our proved reserves as of December 31, 2016 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the 12 months ended on such date. For December 31, 2016, these average prices were $42.75 per Bbl for oil and $2.49 per MMBtu for natural gas. Pricing was adjusted for basis differentials by field based on our historical realized prices. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. |
The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Sustained lower prices will cause the unweighted arithmetic average to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced and may necessitate future write-downs.
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Internal Controls over Reserve Estimates and Qualifications of Technical Persons
Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and our peers and in accordance with the 2007 Petroleum Resources Management System sponsored and approved by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers. The reserve estimation process begins with our Corporate Planning and Reserves department, which gathers and analyzes much of the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by our land department. Lease operating and capital expenses are provided by our accounting department and reviewed by the Corporate Planning and Reserves department. Tim Turner, our Vice President of Corporate Planning and Reserves, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:
• | Over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves; |
• | Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Masters of Business Administration from Oklahoma City University in 1988; and |
• | Registered Professional Engineer in Oklahoma. |
Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developednon-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields.
We maintain internal controls including the following to ensure the reliability of reserves estimations:
• | no employee’s compensation is tied to the amount of reserves booked; |
• | we follow comprehensiveSEC-compliant internal policies to determine and report proved reserves; |
• | reserve estimates are made by experienced reservoir engineers or under their direct supervision; and |
• | each quarter, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and all new PUD additions. |
Ryder Scott, a third-party consulting firm, audited 96.6% and 99.7% of our December 31, 2016 total company and STACK proved reserves, respectively, on a 6:1 MCF/BBL conversion basis.
The qualifications of the technical persons at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.
Kevin Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin. Mr. Gangluff is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
Michael Stell earned a B.S. in Chemical Engineering at Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. Mr. Stell is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and over
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35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
The reserve audits by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s RegulationS-K, Item 1202.
A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within RegulationS-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
Proved Undeveloped Reserves
At December 31, 2016, we had PUDs of 98.4 MMBOE, or approximately 71% of total proved reserves. The PUDs are primarily in the STACK. Total PUDs at December 31, 2015 were 44.6 MMBOE or approximately 57% of total proved reserves.
The following table reflects the changes in PUDs during 2016 for us and for our STACK Assets:
The Company | STACK Assets | |||||||
(MBOE) | ||||||||
Proved undeveloped reserves, December 31, 2015 | 44,624 | 41,927 | ||||||
Converted to proved developed | (1,509 | ) | (843 | ) | ||||
Proved undeveloped reserve extensions and discoveries | 51,306 | 51,306 | ||||||
Proved undeveloped reserves acquired | — | — | ||||||
Proved undeveloped reserves sold | — | — | ||||||
Proved undeveloped reserve revisions | 3,965 | 4,084 | ||||||
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Proved undeveloped reserves, December 31, 2016 | 98,386 | 96,474 | ||||||
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PUDs converted to proved developed reserves were primarily in the STACK, our most active development area. During 2016, we incurred approximately $8.4 million in expenditures to convert the December 31, 2015 PUDs to proved developed reserves. In addition, we spent approximately $2.7 million to convert PUDs that were added during 2016 to proved developed reserves, a portion of these drilling costs were funded through the joint development agreement. Extensions and discoveries were due to increases in PUD reserves associated with our successful drilling activity in the STACK. In 2016, we had positive revisions of 7,322 MBOE due to increased efficiencies of operations at our midstream plant in Oklahoma, which were partially offset by negative price revisions of 3,357 MBOE. These reserves were moved out of the PUD reserve category in compliance with the SEC five-year rule. Estimated future development costs, including plugging and abandonment cost, for PUDs remaining are approximately $634.5 million at December 31, 2016.
We expect that approximately $255.0 million of our 2017 capital expenditure budget will be used for drilling and completion, which we expect to finance through cash flow from operations, our joint development
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agreement with BCE, borrowings under Alta Mesa’s senior secured revolving credit facility and other sources of capital, including the capital contributed by the Riverstone Contributor in connection with the execution of the Riverstone Contribution Agreement. Based on our current rig forecast, we expect that approximately $30.0 million of the 2017 drilling and completion portion of the budget will be expended to drill 20 wells to convert 5.604 net MMBOE of proved undeveloped reserves to proved developed reserves in 2017. A portion of these drilling costs were funded through the BCE joint development agreement.
Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time. We will be required to remove our PUDs if we do not drill those reserves within the required five year time frame, unless specific circumstances justify a longer time. All of our PUDs as of December 31, 2016 were scheduled to be drilled within five years of the original date of booking. The future development of such proved undeveloped reserves is dependent on future commodity prices, top value projects, maximization of present value and production volumes, drilling obligations, anticipated availability of rigs, the need to hold acreage by production, costs and other economic assumptions in our forecasts. Lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our PUDs in the future, which may cause us to decrease the amount of our PUDs we expect to develop within the five-year time frame. In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop at future SEC pricing, which would cause us to remove them from the proved undeveloped category.
We reevaluate our five year plan supporting ouryear-end fiscal results annually based upon the factors listed above. However, the relative proportion of total PUD reserves that we develop over the next five years will not be uniform year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells (wells where a third-party operator has elected to drill a well and we are faced with either drilling the well or incurring penalties or where we need to drill or recomplete a well to preserve a lease), drilling acreage to hold it with production, and the inclusion of new acquisitions with associated PUDs. When developing our long range plan, we prioritize drilling based on many factors including product prices, capital availability and expected rates of return. As a result, we may drill PUDs with smaller net reserves but with higher returns.
During 2016 and 2017, we focused on drilling wells to hold our acreage and expand our proved reserves, as opposed to drilling PUD locations for development purposes as most of our PUDs are currently held by production. We anticipate drilling in excess of 200 wells in each of the following five years. Atyear-end 2016, we had 272 PUD locations in our inventory and, of these locations, 259 are operated by us. During 2018 and 2019, we are only required to drill 56 PUD wells and will begin pattern development as we continue to focus on drilling other wells to expand our proved reserves. By 2020 and 2021, we will need to have drilled 64 and 152 wells, respectively. Accordingly, we anticipate drilling the large majority of our currently booked PUDs in the aggregate as drilling commitments become due in 2020 and 2021.
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Production, Price and Production Cost History
The following table sets forth certain information regarding our production volumes, average prices received and average production costs associated with our sale of oil, natural gas and natural gas liquids for the periods indicated below. The data below include the effects of the amounts we reclassified from natural gas volumes and revenues to natural gas liquids volumes and revenues for the periods indicated.
Nine Months Ended September 30, | Year Ended December 31, | |||||||||||||||
2017 | 2016 | 2015 | 2014 | |||||||||||||
Net production: | ||||||||||||||||
Oil (MBbls) | 3,533 | 4,001 | 4,203 | 3,770 | ||||||||||||
Natural gas (MMcf) | 14,073 | 13,959 | 11,900 | 14,449 | ||||||||||||
Natural gas liquids (MBbls) | 995 | 956 | 678 | 537 | ||||||||||||
Total (MBOE) | 6,873 | 7,284 | 6,865 | 6,715 | ||||||||||||
Total (MMcfe) | 41,237 | 43,702 | 41,187 | 40,290 | ||||||||||||
Average sales price per unit before hedging effects: | ||||||||||||||||
Oil (per Bbl) | $ | 48.01 | $ | 40.91 | $ | 47.54 | $ | 92.27 | ||||||||
Natural gas (per Mcf) | 2.68 | 2.22 | 2.57 | 4.50 | ||||||||||||
Natural gas liquids (per Bbl) | 22.93 | 16.38 | 16.01 | 34.04 | ||||||||||||
Combined (per BOE) | 33.49 | 28.87 | 35.15 | 64.20 | ||||||||||||
Combined (per MMcfe) | 5.58 | 4.81 | 5.86 | 10.70 | ||||||||||||
Average sales price per unit after hedging effects: | ||||||||||||||||
Oil (per Bbl) | $ | 48.25 | $ | 61.53 | $ | 67.73 | $ | 93.38 | ||||||||
Natural gas (per Mcf) | 2.81 | 2.68 | 4.43 | 4.87 | ||||||||||||
Natural gas liquids (per Bbl) | 22.14 | 16.04 | 16.01 | 34.04 | ||||||||||||
Combined (per BOE) | 33.75 | 41.05 | 50.73 | 65.62 | ||||||||||||
Combined (per MMcfe) | 5.63 | 6.84 | 8.45 | 10.94 | ||||||||||||
Average costs per BOE: | ||||||||||||||||
Lease and plant operating expense | $ | 7.25 | $ | 7.81 | $ | 9.86 | $ | 9.63 | ||||||||
Marketing and transportation expense | 3.14 | 1.83 | 0.59 | 1.36 | ||||||||||||
Production and ad valorem taxes | 1.28 | 1.48 | 2.20 | 4.20 | ||||||||||||
Workover expense | 0.74 | 0.65 | 0.95 | 1.33 |
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The following table provides a summary of STACK production, average sales prices and average production costs for the STACK, which contributed approximately 93% of our total proved reserves as of December 31, 2016.
Nine Months Ended September 30, | Year Ended December 31, | |||||||||||||||
STACK Assets | 2017 | 2016 | 2015 | 2014 | ||||||||||||
Net production: | ||||||||||||||||
Oil (MBbls) | 2,783 | 2,570 | 2,006 | 1,072 | ||||||||||||
Natural gas (MMcf) | 10,733 | 8,247 | 4,276 | 2,083 | ||||||||||||
Natural gas liquids (MBbls) | 911 | 823 | 499 | 316 | ||||||||||||
Total (MBOE) | 5,482 | 4,768 | 3,218 | 1,734 | ||||||||||||
Total (MMcfe) | 32,895 | 28,610 | 19,310 | 10,407 | ||||||||||||
Average sales price per unit before hedging effects: | ||||||||||||||||
Oil (per Bbl) | $ | 47.97 | $ | 41.16 | $ | 45.90 | $ | 89.34 | ||||||||
Natural gas (per Mcf) | 2.78 | 2.43 | 2.51 | 4.34 | ||||||||||||
Natural gas liquids (per Bbl) | 23.27 | 17.21 | 16.74 | 34.09 | ||||||||||||
Combined (per BOE) | 33.65 | 29.35 | 34.55 | 66.61 | ||||||||||||
Combined (per MMcfe) | 5.61 | 4.89 | 5.76 | 11.10 | ||||||||||||
Average production costs per BOE: | ||||||||||||||||
Lease and plant operating expense | $ | 4.55 | $ | 4.75 | $ | 6.40 | $ | 7.60 | ||||||||
Marketing and transportation expense | 3.74 | 2.44 | 0.49 | 0.63 | ||||||||||||
Production and ad valorem taxes | 0.69 | 0.58 | 0.58 | 1.45 | ||||||||||||
Workover expense | 0.57 | 0.72 | 0.78 | 1.49 | ||||||||||||
Average production costs per Mcfe: | ||||||||||||||||
Lease and plant operating expense | $ | 0.76 | $ | 0.79 | $ | 1.07 | $ | 1.27 | ||||||||
Marketing and transportation expense | 0.62 | 0.41 | 0.08 | 0.10 | ||||||||||||
Production and ad valorem taxes | 0.11 | 0.10 | 0.10 | 0.24 | ||||||||||||
Workover expense | 0.10 | 0.12 | 0.13 | 0.25 |
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12 month-weighted average price to decrease over time as the lower prices are reflected in the average price.
Delivery Commitments
As of December 31, 2016, we had no commitments to provide a fixed quantity of oil, natural gas or natural gas liquids.
Drilling Activity
The following tables sets forth for the periods indicated below, the number of net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated. 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.
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The Company
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Development wells (net): | ||||||||||||
Productive | 29.9 | 34.6 | 46.6 | |||||||||
Dry | — | 2.0 | 0.1 | |||||||||
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Total development wells | 29.9 | 36.6 | 46.7 | |||||||||
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Exploratory wells (net): | ||||||||||||
Productive | 3.0 | 3.9 | 1.0 | |||||||||
Dry | — | 4.9 | 5.6 | |||||||||
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Total exploratory wells | 3.0 | 8.8 | 6.6 | |||||||||
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STACK Assets
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Development wells (net): | ||||||||||||
Productive | 29.9 | 28.1 | 30.2 | |||||||||
Dry | — | — | — | |||||||||
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Total development wells | 29.9 | 28.1 | 30.2 | |||||||||
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Exploratory wells (net): | ||||||||||||
Productive | 0 | 0 | 0 | |||||||||
Dry | 0 | 0 | 0 | |||||||||
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Total exploratory wells | 0 | 0 | 0 | |||||||||
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Present Activities
As of September 30, 2017, we were drilling 43 gross (26.1 net) wells in progress.
Productive Wells
The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2016:
December 31, 2016 | ||||||||
Gross | Net | |||||||
Oil Wells: | ||||||||
STACK | 435 | 319.1 | ||||||
Weeks Island Area | 54 | 51.8 | ||||||
Other | 73 | 26.4 | ||||||
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All properties | 562 | 397.3 | ||||||
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Natural gas wells | ||||||||
STACK | 32 | 19.8 | ||||||
Weeks Island Area | 3 | 2.8 | ||||||
Other | 84 | 42.2 | ||||||
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All properties | 119 | 64.8 | ||||||
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Of the total well count as of December 31, 2016, 3 gross wells (2.6 net), are multiple completions.
Productive wells are producing wells,shut-in wells we deem capable of production, wells awaiting completion, plus wells that are drilled/cased and completed, but awaiting pipelinehook-up. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests we own in gross wells.
Developed and Undeveloped Acreage Position
The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the United States:
Developed Acres | Undeveloped Acres | Total Acres | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Property: | ||||||||||||||||||||||||
STACK | 94,771 | 70,835 | 28,613 | 26,719 | 123,384 | 97,554 | ||||||||||||||||||
Weeks Island Area | 9,940 | 9,940 | 2,219 | 2,219 | 12,159 | 12,159 | ||||||||||||||||||
Other | 59,350 | 26,156 | 369,057 | 309,011 | 428,407 | 335,167 | ||||||||||||||||||
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All properties | 164,061 | 106,931 | 399,889 | 337,949 | 563,950 | 444,880 | ||||||||||||||||||
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As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases, by paying delay rentals during the remaining primary term of leases, pooling process, automatic extensions or negotiated extensions of the leases, and other terms of the leases such asshut-in payments. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.
Undeveloped Acreage Expirations
The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:
2017 | 2018 | 2019 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Property: | ||||||||||||||||||||||||
STACK | 5,225 | 4,415 | 7,183 | 6,739 | 6,968 | 6,151 | ||||||||||||||||||
Weeks Island Area | 1,824 | 1,824 | 395 | 395 | — | — | ||||||||||||||||||
Northwest | 17,331 | 11,635 | 28,903 | 19,424 | 36,507 | 24,834 | ||||||||||||||||||
Other | 2,508 | 1,774 | 17,670 | 9,713 | 5,383 | 4,470 | ||||||||||||||||||
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All properties | 26,888 | 19,648 | 54,151 | 36,271 | 48,858 | 35,455 | ||||||||||||||||||
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We have lease acreage that is generally subject to lease expirations if initial wells are not drilled within a specified period, generally a period of three to five years. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by maintaining the lease through: (i) the commencing operations for drilling, completion and production operations, (ii) pooling process, (iii) production, (iv) automatic extensions or negotiated extensions of the leases and (v) other terms of the leases such asshut-in payments. As of
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December 31, 2016, the vast majority of our acreage does not have associated proved undeveloped reserves, and proved undeveloped reserves attributed to acreage in which the lease expiration date precedes the scheduled initial drilling date is primarily outside the STACK and is not material. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to fee lease term of our competitors as they relate to both primary term and royalty interests.
Non-STACK Assets
Alta Mesa produced oil and natural gas in the U.S. from its properties that are divided by major geographical area, including: (1) the STACK in Oklahoma, (2) the Weeks Island Area in South Louisiana and (3) Other (together with the Weeks Island Area, the “non-STACK assets”). Pursuant to the Alta Mesa Contribution Agreement, Alta Mesa sold the Weeks Island assets for approximately $22.6 million in cash on December 30, 2017 and transferred to its existing owners (other than the Riverstone Contributor) the remaining non-STACK assets and liabilities prior to the Closing. The proceeds of the sale of the Weeks Island assets were used to reduce Alta Mesa’s outstanding indebtedness, resulting in an increase in the consideration payable to the owners of Alta Mesa (other than the Riverstone Contributor) in the Business Combination. Our operations in the STACK differ from its operations in other areas in that (a) we operate the substantial majority of its STACK properties; (b) our operations in the STACK consist of a large, highly contiguous acreage position with multi-year inventory of low-risk horizontal drilling locations; and (c) our operations in the STACK focus on unconventional drilling techniques. The sale and transfer of the non-STACK assets and shift to focus solely on oil and gas development in the STACK represents a strategic shift in the operations of Alta Mesa.
Weeks Island Area, South Louisiana
The Weeks Island Area, located in Iberia and St. Mary Parishes, Louisiana, consists of the historically prolific Weeks Island and Cote Blanche Island fields. The Weeks Island field, located in Iberia Parish, Louisiana, is an oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome. The Cote Blanche Island field, located near Weeks Island field in St. Mary Parish, is also a salt dome structure. As of December 31, 2016, Alta Mesa had a 96% average working interest in a total of 57 gross producing wells, and had identified 7 PUD locations in the Weeks Island Area. Average daily production from the Weeks Island Area in the third quarter of 2017 was approximately 2,200 BOE per day. As of September 30, 2017, the Weeks Island Area represented approximately 7.46% of Alta Mesa’s total assets and generated 12.96% of Alta Mesa’s total operating revenues. The Weeks Island assets were sold for approximately $22.6 million in cash on December 30, 2017.
Other Assets
Alta Mesa conducted operations in other areas in East Texas, Florida and other fields in South Louisiana and continually evaluates the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans. Average daily production from Alta Mesa’s other properties in the third quarter of 2017 was approximately 2,669 BOE per day. As of September 30, 2017, Alta Mesa’s other properties represented approximately 1.86% of its total assets and generated 10.77% of its total operating revenues.
OUR MIDSTREAM BUSINESS
Our midstream energy asset network includes approximately 308 miles of existing low and high pressure pipelines, a 60 MMcf/d cryogenic natural gas processing plant, 10 MMcf/d in offtake processing, compression facilities, crude storage, NGL storage and purchasing and marketing capabilities.
We believe that this high quality gathering and processing system is strategically positioned for growth in the highly active STACK play, which is expected to face takeaway constraints as a consequence of increased drilling activity and improving well results. The STACK play is one of the most prolific resource basins in North America, with economic wells and continued activity despite the continuity of lower crude oil and natural gas prices.
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Recent Developments
We entered into a gas processing agreement (the “offtake agreement”) with a third-party operator for 120,000 MMBtu/d into Panhandle Eastern Pipeline Company, LP’s (“PEPL”) pipeline system. The offtake agreement is expected to result in 80 MMcf/d of rich natural gas priority processing capacity, post-blending. The third-party operator’s 1.3 Bcf/d natural gas processing complex is located in the state of Kansas. The offtake agreement will provide (i) optionality for processing natural gas throughput volumes and (ii) our ownership and control of an interconnect into PEPL’s pipeline system.
The primary term of the offtake agreement is four years, with an option to extend for two years after the primary term. Thereafter, in the secondary term of the offtake agreement, we have the right to renew the agreement annually.
Midstream Assets
Our Phase I assets include a natural gas cryogenic processing plant with a current processing capacity of 60 MMcf/d and 1,200 Bbl/d condensate stabilizer. Phase I includes approximately 160 miles oflow-pressure crude oil and natural gas gathering pipelines, approximately 50 miles of high pressure natural gas gathering pipelines, 15,000 horsepower of field compression and 4,000 horsepower of natural gas residue compression. Additionally, we have fixed transportation capacity on natural gas pipelines operated by PEPL, ONEOK Gas Transportation, LLC (“ONEOK”) and Superior Pipeline Company, LLC (“Superior”). We also have fixed transportation capacity on a NGL pipeline operated by Chisholm Pipeline Company (“Chisholm”) and owned by Phillips 66. Our other assets include a 50,000 Bbl crude storage terminal with six truck loading lease automated custody transfer units, three NGL bullet tanks with 90,000 gallon capacity per tank and producer connections with 54 central delivery point receipt connections serving 188 units.
Our Phase II assets include a second natural gas cryogenic processing facility, which will be located adjacent to our existing 60 MMcf/d cryogenic processing facility, with a processing capacity of 200 MMcf/d. Phase II includes approximately 96 miles of low and high-pressure pipelines primarily for natural gas gathering and transportation, 20,000 horsepower of field compression and 12,500 horsepower of natural gas residue compression. We plan to contract for additional fixed transportation capacity on ONEOK’s pipeline. Additionally, we will install equipment for rich gas blending purposes related to the offtake capacity estimated to be 80 MMcf/d, post-blending.
Our Area of Operation
Our existing midstream infrastructure and facilities are located in Kingfisher County, Oklahoma and Garfield County, Oklahoma in the STACK play. The system was initially designed to primarily serve Alta Mesa and overlays our contiguous acreage position in theup-dip oil window of the STACK play, located in Kingfisher County, Oklahoma. Our existing infrastructure has been developed to provide crude oil gathering, natural gas gathering and processing and strategic residue takeaway optionality for third-party producers. We have contracted long term(10-15 year) acreage dedications and wellbore commitments from six customers.
The STACK play has seen consistent growth in horizontal drilling activity over the past several years. The Anadarko basin is a prolific producer of both petroleum and natural gas. While theDevonian—Mississippian-age Woodford Shale is the most well-known source rock in the basin, other potential source rocks include the Ordovician (Simpson Group shales), Mississippian (Meramec and Springer shales), and thick, dark Pennsylvanian shales. The STACK play targets the liquids-rich, UpperDevonian-age Woodford formation. The STACK play also targets the overlying,Mississippian-age Meramec and Osage Group and underlying Hunton. The most prominent formations are the Meramec, Osage and Woodford.
Currently, we are in the process of expanding our infrastructure to Major County, Oklahoma and Blaine County, Oklahoma. The crude oil and natural gas reservoir development of the STACK play has progressed
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westward, and we expect to compete in the region for third-party volumes. We believe that our ability to provide flow assurance through our firm residue takeaway contracts on PEPL and ONEOK Partners, LP (“OGT”) should provide us with a competitive advantage.
Other Acreage Dedications
We have contracted to provide natural gas gathering and processing services to five other producer customers beyond ourselves. Collectively, these five customers have provided us with acreage dedications and resource allocations totaling approximately 180,000 acres. Theall-in rates for these customers range from $0.42/MMBtu, plus 2.5% of proceeds to $1.05/MMBtu. The contracted rates are a result of negotiation after analysis of the expected economic returns for gathering and processing certain acreage.
Access to Downstream Markets
We contracted for fixed transportation of natural gas residue and NGL volumes prior to commissioning the 60 MMcf/d cryogenic processing plant. We identified that the upstream economics of the STACK play were improving and that produced hydrocarbon volumes would outpace the existing takeaway capacity in the region. As such, we acquired fixed transportation contracts at low transportation rates early in the development and expansion of the STACK play. The amount of natural gas residue and fixed transportation capacity allowed us to provide flow assurance to producers, and, thus, we continue to possess a strategic competitive advantage in the contracting of additional producer gas gathering and processing agreements.
In early 2016, we entered into agreements providing for 100,000 Dth/d of natural gas residue fixed transportation capacity through 2036 on PEPL’s pipeline system. PEPL is an interstate pipeline system owned by Energy Transfer Partners, LP. We contracted for an incremental 20,000 Dth/d of fixed transportation capacity on the PEPL pipeline system beginning on August 1, 2017 for a term of one year, with a first right for annual renewal. We also constructed an interconnect to the PEPL pipeline system, which provides access toend-user markets in the upper Midwest and West.
In early 2017, we contracted for additional natural gas residue fixed transportation capacity providing for approximately 100,000 Dth/d on ONEOK’s pipeline in the OGT system. The term of the 100,000 Dth/d begins in June 2018 and is for a term of 10 years. In June 2017, we contracted for natural gas residue fixed transportation capacity on the OGT system for a term of five years, with first year capacity of 50,000 Dth/d, which reduces to 25,000 Dth/d for the remaining four years of the term. The OGT system is an intrastate pipeline transmission with peak capacity of 2.1 Bcf/d owned by OGT. Effective September 1, 2017, we assigned the10-year, 100,000 Dth/d of the OGT capacity to Alta Mesa.
We also have fixed transportation and processing capacity through Superior’s pipeline for approximately 10,000 Mcf/d. We have entered into a letter agreement to assign 5,000 Mcf/d of the Superior capacity to Alta Mesa, subject to certain conditions.
We recognized that the natural gas takeaway market was tightening and that the intrastate pipeline market was near saturation. Currently, we have contracted for approximately 280,000 Dth/d of natural gas residue fixed transportation capacity, which is expected to continue providing producers with a valuable egress solution.
In 2016, we contracted for NGL fixed transportation capacity on the NGL pipeline operated by Chisholm for three years. The contracts require us to deliver a minimum daily volume of NGLs with annual increases. The agreements also require that we deliver 4,200 and 7,125 Bbls/d of NGLs for the 12 months ending June 30, 2018, and 2019, respectively. We connect to Chisholm’sY-Grade system at an interconnect, which provides access to the Conway market. The capacity associated with the Chisholm pipeline provides flow assurance to producers and provides an outlet for a portion of the expected NGL volumes derived from the existing producers that have provided acreage dedications and resource allocations to producers.
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Marketing and Customers
The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
We sell the oil and natural gas from several properties we operate primarily through a marketing agreement with ARM Energy Management, LLC (“AEM”). We are a part owner of AEM at less than 10%. AEM markets our oil and natural gas and subsequently sells it under short-term contracts generally withmonth-to-month pricing based on published regional indices, with differentials for transportation, location and quality taken into account. AEM remits monthly collections of these sales to us and receives a 1% marketing fee. Our marketing agreement with AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years and for early termination. During the second half of 2013 and throughout 2014 to 2016, AEM marketed the majority of our production from operated fields.
Natural gas liquids are sold under various contracts with processors typically in the vicinity of the production at spot market rates, after processing costs.
Our gathering and transmission pipelines have connections with major intrastate and interstate pipelines, which we believe have ample natural gas and NGL supplies in excess of the volumes required for the operation of these systems. We evaluate well and reservoir data that is either publicly available or furnished by producers or other service providers in connection with the construction and acquisition of our gathering systems and assets to determine the availability of natural gas, NGLs, crude oil and condensate supply for our systems and assets and/or obtains an minimum volume commitment from the producer that results in a rate of return on investment. We do not routinely obtain independent evaluations of reserves dedicated to our systems and assets due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our systems and assets or the anticipated life of such producing reserves.
For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities.
We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available. Trade accounts receivable are not collateralized or otherwise secured.
Credit Risk
We are subject to risk of loss resulting from nonpayment or nonperformance by our customers and other counterparties. We diligently attempt to ensure that we issue credit to only credit-worthy customers. The combination of a reduction of cash flow resulting from lower commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in the liquidity of our customers and their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.
Competition
Our E&P Business encounters intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and
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individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and mineral leases and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could 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 this highly competitive environment.
We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.
We compete for capital in the domestic financial marketplace to fund our exploration and development activities to the extent our operations cannot support them at any given time. See “Risk Factors—Risks Related to the E&P Business—Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.”
Our Midstream Business of providing gathering, processing and marketing services for crude oil, natural gas and NGLs is highly competitive. We face strong competition in obtaining crude oil, natural gas and NGL volumes, including from major integrated and independent exploration and production companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport, store or market crude oil and natural gas. Competition for crude oil and natural gas supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. For areas where acreage is not dedicated to us, we will compete with similar enterprises in providing additional gathering and processing services in our area of operation, which may offer more services or have strong financial resources and access to larger volumes of crude oil, natural gas and NGLs than we do. In marketing crude oil, natural gas and NGLs, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national oil and natural gas producers, gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly and through affiliates in marketing activities that compete with our marketing operations.
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.
Oklahoma Forced Pooling Process
In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to ensure all working interest owners participate in drilling and spacing units for wells we propose to drill as operator our STACK acreage. Where applicable, this process allows us to increase our working interest in those units. Any such increase in working interest would lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be
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developed, the party may commence a “forced pooling” process. Under current regulations, drilling and spacing units for our targeted horizons in our STACK acreage are based on drilling a maximum of four to eight horizontal wells, depending on the formation, on a land section consisting of 640 acres. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the OCC and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.
Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.
The availability of forced pooling means that it normally is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.
As a result of forced pooling processes, we have increased our working interest in approximately 95% of the 112 total operated horizontal wells we have drilled on our STACK acreage since January 1, 2014. In those wells in which forced pooling proceedings were initiated, we increased our working interest by an average of approximately 15% of our initial working interest in the drilling unit. In one instance in 2016, we proposed and drilled a well as operator in a section where our working interest ownership was initially approximately 10%, which through the implementation of the forced pooling process increased our working interest to approximately 90%. In recent years, the collective working interest of third-party owners of mineral rights in these drilling units who have elected to participate in these wells has been low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic play in the current price and cost environment, we believe that third-party interest holders may be more likely to bear their share of the costs of the proposed future wells on our acreage. Nevertheless, we expect that forced pooling will continue to increase our leasehold interests within our STACK acreage. The successful use of forced pooling to increase our working interest in proposed wells that are attributed undeveloped reserves is not reflected in our Reserve Reports.
Title to Properties
In our E&P Business, as is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other
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encumbrances, easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.
For our Midstream Business, we have leased or acquired easements,rights-of-way, permits or licenses without any material challenge known to us relating to the title to the land upon which our assets are located, and we believe that we have satisfactory interests in such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement,right-of-way, permit or license held by us or to our title to any material lease, easement,right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements,rights-of-way, permits and licenses.
Employees
As of September 30, 2017, we had 269 full-time employees in our E&P Business. Our Midstream Business has no employees. Under the Operator Agreement, Asset Risk Management, LLC (“ARM”) operates, maintains and administers our Midstream Business, and ARM also provides management services to us. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.
Insurance
In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.
Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1.8 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.
Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.
We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.
Were-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In
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addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.
Legal Proceedings
Environmental Claims
Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at September 30, 2017.
Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. As of December 31, 2016, our revised estimated remediation liability for soil contamination in Florida was approximately $0.1 million and as of December 31, 2015, we had estimated a liability of $1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the consolidated balance sheets included in the financial statements herein. Our existing equity owners, other than the Riverstone Contributor, will assume the case and liabilities related thereto as part of the transfer of the remainingnon-STACK asset to them.
Title/Lease Disputes
Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.
Litigation
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary (“OEA”), and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with OEA containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) OEA, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against OEA only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants, including us. While we may incur costs or losses in connection with this litigation, we have not accrued a loss contingency because we are currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves.
On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and
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contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of September 30, 2017, we have accrued approximately $3.2 million ($0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years.
On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment ornon-payment of royalty. The suit alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. As of September 30, 2017, we believe losses are probable and estimable in connection with this litigation and have accrued approximately $4.5 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets.
Other
We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome cannot be reasonably estimated; however, in the opinion of our management, such litigation and claims will be resolved without material adverse effect on our financial condition, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.
Environmental and Occupational Safety and Health Matters
Our oil and natural gas exploration and production operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental agencies, including the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things:
• | require the acquisition of various permits before drilling and other regulated activities commence; |
• | require the installation of pollution control equipment in connection with operations and place other conditions on our operations; |
• | place restrictions on the use of the material based on our operations and upon the disposal of waste from our operations; |
• | restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities; |
• | limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; |
• | require remedial measures to mitigate pollution from former and ongoing operations, including site restoration, pit closure and plugging of abandoned wells; and |
• | impose specific safety and health criteria addressing worker protection. |
These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action
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obligations, occurrence of delays or cancellations in the permitting, performance or expansion of projects and in issuance of orders enjoining performance in particular areas fornon-compliance.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, For example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 to 2019, although the outlook for this initiative remains unclear with the change in Presidential administration. Consequently, any changes in environmental laws and regulations orre-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of some of the more significant existing environmental and occupational safety and health laws, and regulations, as amended from time to time, to which our business operations are subject.
Non-hazardous and Hazardous Wastes and Hazardous Substances Handling
The federal RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup ofnon-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringentnon-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified asnon-hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by severalnon-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. 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 waste, which could have a material adverse effect on our financial condition and results of operations.
The federal CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” (or in the case of state laws, other classes of materials) into the environment. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of hazardous substances. These classes of persons, orso-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of
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a hazardous substance released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. We generate materials in the course of our operations that may be regulated as hazardous substances.
We currently own, lease or operate and in the past have owned, leased or operated numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such materials have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could be material.
Water Discharges and Subsurface Injections
The federal CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.
The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Army Corps”). The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. In February 2017, President Trump signed an executive order directing the EPA and the Army Corps to begin a process to revise or rescind these rules; the agencies published a notice of intent on March 6, 2017 to review and rescind or revise the rules and the U.S. Department of Justice filed a motion with the U.S. Supreme Court on March 6, 2017 requesting a court stay of its review of the rules. The outlook for these rules is unclear. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures fornon-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The primary federal law related to oil spill liability is the OPA, which amends and augments oil spill provisions of the CWA 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 United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns 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 to the liability imposed by the OPA, they are limited.
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Our underground injection operations are regulated pursuant to the UIC program established under the federal SDWA and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.
Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The OCC has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. More recently, in December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and natural gas wastewater injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection well locations or otherwise, or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.
Hydraulic Fracturing
Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In the STACK play, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We also perform hydraulic fracturing in vertical wells in our East
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Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among the target zones are the Wilcox and Frio formations.
Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA’s UIC program exempts EPA regulation of most hydraulic fracturing except for hydraulic fracturing activities involving the use of diesel. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In other examples, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, in 2015, the BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands, which has been challenged in court. However, the BLM is in the process of rescinding the 2015 rule. Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding TSCA reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.
Many states, including Oklahoma, where we conduct operations, and other regional and local regulatory authorities have enacted, and other states or other regional and local authorities are considering, laws or other regulatory initiatives on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit drilling in general or hydraulic fracturing in particular, in certain circumstances. Some states have also considered or adopted other restrictions or regulations on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although Oklahoma has taken steps to limit the authority of local governments to regulate oil and natural gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our production and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.
Air Emissions
Our current and future operations are subject to the federal CAA and regulations promulgated thereunder and under comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and impose various control, monitoring, and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agencypre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related
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issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources or require us to incur additional capital expenditures. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition, results of operations or cash flows, and the requirements are not expected to be more burdensome to us than to any similarly situated company.
Effective May 15, 2012, the EPA promulgated rules under the CAA that established new air emission controls for oil and natural gas production, pipelines and processing operations under the NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) programs. These rules require the control of emissions through reduced emission (or “green”) completions and establish specific new requirements regarding emissions from wet seal and reciprocating compressors, pneumatic controllers, and storage vessels at production facilities, gathering systems, boosting facilities, and onshore natural gas processing plants. In addition, the rules revised existing requirements for volatile organic compound (“VOC”) emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines. In October 2012, several challenges to the EPA’s NSPS and NESHAPs rules for the industry were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since revised certain aspects of the rules and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such proceedings, the rules may be further modified or rescinded or the EPA may issue new rules. We cannot predict the costs of compliance with any modified or newly issued rules.
In partial response to the issues raised regarding the 2012 rulemaking, the EPA published new rules in June 2016 to regulate emissions of methane and VOCs from new and modified sources in the oil and gas sector. However, in April 2017, the EPA announced that it will review this rule for new, modified or reconstructed facilities and will initiate reconsideration proceedings to potentially revise or rescind portions of the rule. Subsequently, on May 31, 2017, the EPA issued a90-day stay of certain requirements under the rule, but this stay was vacated by a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017 and again by anen banc D.C. Circuit on July 31, 2017. In the interim, on July 16, 2017, the EPA issued a proposed rule that would provide atwo-year extension of the initial90-day stay. Substantial uncertainty exists with respect to implementation of this methane rule. The EPA has also finalized a rule regarding alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. During the Obama Administration, other federal agencies, including the BLM, PHMSA, and the Department of Energy, proposed or finalized new or more stringent regulations for the oil and gas sector in order to further reduce methane emissions. For example, the BLM adopted new rules on November 15, 2016, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On June 15, 2017, the BLM postponed indefinitely compliance dates for certain aspects of these rules, pending judicial review. As a result of this continued regulatory focus and other factors, additional GHG regulation of the oil and gas industry remains possible. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs for us and for other companies in our industry. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules, as well as any new state rules, may also make it more difficult for our suppliers and customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business. However, the status of recent and future rules and rulemaking initiatives under the new Trump Administration is uncertain.
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Climate Change Regulation and Legislation
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration ofcap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published Subpart OOOOa, requirements for certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued Subpart OOOO, requirements issued in 2012 by using certain equipment-specific emissions control practices. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. With the change in Presidential administration, the ongoing commitment of the United States to the Paris Agreement is unclear.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we produce and lower the value of our reserves.
Finally, it should be noted 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 such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient ornon-routine operating practices necessitated by such climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
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Activities on Federal Lands
Our only activity on federal lands is on ournon-STACK assets that were sold to a third party or transferred to the Alta Mesa Contributor. Oil and natural gas exploration and production activities on federal lands, including Indian lands, may be subject to the federal NEPA, which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions and costs upon the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we could incur added costs, which may be significant.
Occupational Safety and Health Matters
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the federal Emergency Planning and CommunityRight-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.
Other Laws and Regulations
Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission by pipeline in some circumstances may also affect the intrastate transportation of oil and natural gas by other means.
Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to
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regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.
Exports of U.S. Crude Oil Production, Natural Gas and Liquefied Natural Gas
The federal government has recently ended itsdecades-old prohibition of exports of oil produced in the lower 48 states of the United States. It is too recent an event to determine the impact this regulatory change may have on our operations or its sales of oil. The general perception in the industry is that ending the prohibition of exports of oil produced in the United States will be positive for producers of U.S. oil. In addition, the U.S. Department of Energy (the “DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulation of the energy sector in Mexico. In addition, the DOE authorizes the export of LNG through LNG export facilities, the construction of which is regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG export facilities being developed and constructed in the U.S. Gulf Coast region. While it is also too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U.S. natural gas.
Drilling and Production
Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the timing of construction or drilling activities, including seasonal wildlife closures; |
• | the rates of production or “allowables”; |
• | the surface use and restoration of properties upon which wells are drilled; |
• | the plugging and abandoning of wells; and |
• | notice to, and consultation with, surface owners and other third parties. |
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, which could negatively affect the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The
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U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Forced Pooling in Oklahoma
The pooling process before the OCC provides a mechanism to develop a unit when two or more of its owners cannot voluntarily agree to pool their interests for the purposes of drilling and development. This procedure, which is standard in an actively developed field in Oklahoma, is specific to a given reservoir. The parties that are the recipient of pooling applications and orders under the OCC may elect to: (i) lease their unleased minerals for stated terms; (ii) participate in the well and pay their proportionate share of costs; or (iii) be bought out for fair, just and reasonable compensation determined by the OCC. Under this process, we pooled 68 sections in 2016 and on average increased our interest in the 68 units by 15%.
Natural Gas Sales and Transportation
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price andnon-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.
Under the EPAct, Congress amended NGA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions fornext-day or next-month delivery.
FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of its excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule-makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, interstate transportation services must be provided on an open- access,non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. FERC-regulated tariffs, under which interstate pipelines provide such open-access
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transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.
Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities asnon-jurisdictional gathering facilities, and FERC has reclassified certainnon- jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas topoint-of-sale locations.
The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968 (the “NGPSA”), as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”).
Pipeline Safety Regulations
Some of our pipelines are subject to regulation by the DOT’s PHMSA pursuant to the NGPSA, with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Act, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and the 2011 Pipeline Safety Act. The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of natural gas, crude oil and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGL and natural gas transmission pipelines in high consequence areas (“HCAs”).
PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators to:
• | perform ongoing assessments of pipeline integrity; |
• | identify and characterize applicable threats to pipeline segments that could impact a HCA; |
• | improve data collection, integration and analysis; |
• | repair and remediate pipelines as necessary; and |
• | implement preventive and mitigating actions. |
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2.0 million for a series of violations. Effective April 27, 2017, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2.09 million for a series of violations, to account for inflation. The PHMSA has also issued a final rule applying safety regulations to certain rurallow-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.
PHMSA regularly revises its pipeline safety regulations. For example, in March 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-
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construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. More recently, in October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a HCA. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in December 2015, the Senate Commerce Committee approved legislation that, among other things, requires PHMSA to conduct an assessment of its inspections process and integrity management programs for natural gas and hazardous liquid pipelines. The legislation would also require PHMSA to prioritize various rulemakings required by the 2011 Pipeline Safety Act and propose and finalize the rules mandated by the act. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas transmission pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements.
In addition, on January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule requires additional event-driven and periodic inspections, requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodatein-line inspection tools. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump Administration on January 20, 2017.
On January 23, 2017, PHMSA published in the Federal Register amendments to the pipeline safety regulations to address requirements of the 2011 Pipeline Safety Act and to update and clarify certain regulatory requirements regarding notifications of accidents and incidents. The final rule also adds provisions for cost recovery for design reviews of certain new projects, renews existing special permits, and incorporates certain standards forin-line inspections and stress corrosion cracking assessments. The effective date of the final rule would have been March 24, 2017; however, the rule is subject to a regulatory freeze pending review by the Trump Administration.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and state requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our financial condition, results of operations or cash flows.
Oil and Natural Gas Liquids Sales and Transportation
Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC, as common carriers, under the Interstate Commerce Act (the “ICA”). The
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FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. 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 are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on anon-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane,iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.
In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.
State Regulation
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
Oklahoma currently imposes on all new wells, both horizontal and vertical, drilled on or after July 1, 2015, a tax 2% of gross production for the first 36 months of production and then at 7% thereafter. There will still be different treatment for a limited number of wells defined as enhanced recovery projects, production enhancement projects, inactive wells and economicallyat-risk oil or gas leases. Horizontal wells drilled prior to July 1, 2015, will continue to be taxed at 1% for 48 months after production commences. Deep wells drilled prior to July 1, 2015, will continue to be taxed at 4% for 48 months, while most other wells drilled prior to July 1, 2015, will be taxed at 7% throughout their productive life. In response to a recent significant earthquake, federal and Oklahoma state regulators imposed limitations on disposal of produced water in two counties. On September 12, 2016, federal and state regulators expanded and modified those emergency orders limiting disposal activity in thetwo-county area. Multiple wells shut down immediately after the earthquake are being allowed to resume operations with volume limits.
Louisiana severance tax laws are more complex than those of other states. Different schedules of taxes are imposed based on the different hydrocarbons produced. The basic (and highest) rate for natural gas is $0.164 per Mcf for full rate wells. The basis (and highest) rate for oil is 12.5% of value for full rate oil and condensate.
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There is a severance tax exemption for oil and gas produced from horizontal wells. Last year, Louisiana imposed on operators of wells a security deposit requirement for plugging and abandonment obligations. Those who own between 11 and 99 wells pay a deposit of $250,000. The fee is $500,000 for every 100 wells. Owners of single wells pay by the depth. The deposit is $7 per foot for the first 3,000 feet with lower rates the deeper the well is drilled.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Other Regulation
In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.
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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 accompanying financial statements and related notes of the Company included elsewhere in this prospectus. The following discussion and analysis 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, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and 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—Risks Related to the E&P Business,” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Prior Company Operations
We have no direct operations and no significant assets other than the ownership of an approximate 44.2% membership interest in SRII Opco. SRII Opco owns all of the outstanding equity ownership interests in each of Alta Mesa and Kingfisher. Alta Mesa is considered our accounting predecessor and, accordingly, the following financial results and discussion and analysis reflect the results of Alta Mesa prior to the Closing. The following discussion also includes information regarding Alta Mesa’snon-STACK assets, which the Company did not acquire in the Business Combination.
For all periods ending on or before February 8, 2018 and for all dates on or before February 8, 2018, the historical financial results contained herein reflect the results of Alta Mesa. On February 9, 2018, SRII Opco acquired all of the economic ownership interests of Alta Mesa and Kingfisher, and as a result, subsequent to February 9, 2018, the historical financial results contained herein reflect the results of Alta Mesa, Kingfisher and the Company. Except as the context otherwise requires, references in the following discussion to the “Company,” “we,” “our” or “us” with respect to periods prior to the Closing are to Alta Mesa and its operations prior to the Closing. Alta Mesa and Kingfisher continue to exist as separate subsidiaries of SRII Opco and those entities are separately financed, with each having debt obligations that are not obligations of the other or of the Company. Consequently, references herein to Alta Mesa and to Kingfisher are to those entities and not to the Company as a whole.
Overview
We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production business in the United States since 1987. Currently, we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the STACK. Historically, we have also operated, developed and explored for conventional oil and natural gas reserves, with our most significant conventional asset being the Weeks Island oil field in Iberia Parish, Louisiana. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with minority interest holders. Pursuant to the Alta Mesa Contribution Agreement, Alta Mesa sold its Weeks Island assets for $22.6 million in cash on December 30, 2017 and transferred to its existing owners (other than the Riverstone Contributor) the remaining non-STACK assets immediately prior to the Closing. The proceeds of the sale of the Weeks Island assets were used to reduce Alta Mesa’s outstanding indebtedness, resulting in an increase in the consideration payable to the owners of Alta Mesa (other than the Riverstone Contributor) in the Business Combination.
Outlook
Our revenue, profitability and future growth depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control. The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years. Accordingly, the success of our
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business is significantly affected by the price of oil due to our current focus on development of oil reserves. Oil prices are subject to significant changes. Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years. Factors affecting oil prices include worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of Alta Mesa’s borrowing base under its senior secured revolving credit facility.
During the last 12 month period ended September 30, 2017, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $53.46 per Bbl in February 2017 to a low of $45.20 per Bbl in June 2017. During the third quarter of 2017, NYMEX WTI prices averaged approximately $48.20 per Bbl compared to $44.94 per Bbl for the same period of 2016. We received an average price of $47.20 per Bbl for the third quarter of 2017 before the effects of hedging. NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also been volatile and ranged from a high of $3.93 per MMBtu in January 2017 to a low of $2.63 in March 2017. During the third quarter of 2017, NYMEX HH prices averaged approximately $3.00 per MMBtu compared to $2.81 per MMBtu for the same period of 2016. We received an average price of $2.50 per Mcf for natural gas in the third quarter of 2017 before the effects of hedging. As of February 6, 2018, NYMEX WTI was $63.39 per Bbl and NYMEX Henry Hub was $2.76 per MMBtu. Commodity prices remain volatile and unpredictable but have improved during the third quarter of 2017 compared to the third quarter of 2016.
In order to mitigate the impact of changes in oil, natural gas and natural gas liquids prices on our cash flows, we are a party to hedging and other price protection contracts, and our management intends to enter into such transactions in the future to reduce the effect of low oil, natural gas and natural gas liquids prices on our cash flows. Our derivative contracts are reported at fair value on our consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and natural gas liquids. Changes in these derivative assets and liabilities are reported in our consolidated statements of operations as gain / loss on derivative contracts, which include both thenon-cash increase and decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In the first nine months of 2017, we recognized a net gain on our derivative contracts of $38.0 million, which includes $1.8 million in cash settlements received on derivative contracts. In 2016, we recognized a net loss on our derivative contracts of $40.5 million, which includes $88.7 million in cash settlements received on derivative contracts. In 2015, we recognized a net gain on our derivative contracts of $124.1 million, which includes $106.9 million in cash settlements received for derivative contracts.
The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil, natural gas and natural gas liquids revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and our management expects these gains and losses to continue to reflect changes in oil and natural gas prices.
As of September 30, 2017, we hedged approximately 73% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $3.18 per MMBtu to $4.43 per MMBtu for natural gas and $50.00 per Bbl to $51.37 per Bbl for oil. If oil and/or natural gas prices continue to decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices.
Depressed oil and natural gas prices have impacted our earnings by necessitating impairment write-downs in some of our properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment
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write-downs. We recordednon-cash impairment expenses of $29.2 million and $14.2 million for the nine months ended September 30, 2017 and 2016, respectively. In the first nine months of 2017 and 2016, write-downs were primarily due to downward revisions in proved reserves in some fields and the effects of decreased prices for oil, natural gas and natural gas liquids. In the first nine months of 2017, our impairments were primarily related to ournon-core areas. Further declines in oil and/or natural gas prices may result in additional impairment expenses. We recordednon-cash impairment expenses of $16.3 million, $176.8 million and $74.9 million during the years ended December 31, 2016, 2015 and 2014, respectively. The 2016 write-downs were primarily due to downward revisions in proved reserves in some fields and decreased prices for oil, natural gas and natural gas liquids. Our impairments were primarily related to our oil and gas properties. For further information, see “—Results of Operations: Year Ended December 31, 2016 Compared to Year Ended December 31, 2015—Impairment Expense.”
The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.
Factors Affecting the Comparability of Future Financial Results of the Company to the Historical Financial Results of Alta Mesa
The future results of operations of the Company attributable to Alta Mesa may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below:
• | The historical consolidated financial statements of Alta Mesa included in this prospectus are based on the financial statements of Alta Mesa prior to the sale of its Weeks Island assets on December 30, 2017 and the transfer of all its remaining non-STACK assets and related liabilities to its existing owners (other than the Riverstone Contributor), which occurred prior to the Closing. The $22.6 million cash proceeds of the sale of the Weeks Island assets were used to reduce Alta Mesa’s outstanding indebtedness, resulting in an increase in the consideration payable to the owners of Alta Mesa (other than the Riverstone Contributor) in the Business Combination. Accordingly, these assets will not be a part of the Company following the Business Combination. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the transfer had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. |
• | In connection with the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco and the Initial Limited Partners. This agreement generally provides for the payment by the Company of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for Class A Common Stock (or, under certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in Kingfisher’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. The Company will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” |
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• | We anticipate that we will account for the effects of these increases in tax basis and payments for such increases under the Tax Receivable Agreement arising from future exchanges as follows: |
• | we do not anticipate recording a liability in connection with the Tax Receivable Agreement upon completion of the Business Combination as we do not expect there to be any exchanges of SRII Opco Common Units at such time; |
• | when future sales or exchanges occur, we will record a debit to the deferred taxes on the balance sheet for the gross amount of the income tax effect along with an offset of 85% of this liability as payable under the Tax Receivable Agreement; the remaining difference between the deferred tax and tax receivable agreement liability will be recorded as additionalpaid-in capital; and |
• | to the extent we have recorded a deferred tax asset for an increase in tax basis to which a benefit is no longer expected to be realized due to lower future taxable income, we will reduce the deferred tax asset with a valuation allowance. |
Additionally, our pro forma results of operations included in the financial statements elsewhere in this prospectus include the following significant adjustments related to our operations as compared to the historical results of operations of Alta Mesa:
• | Operating Revenues.We expect that our oil, natural gas and natural gas liquid operating revenues will initially be lower as compared to historical data, primarily due to the Alta Mesanon-STACK Assets Divestiture which transpired prior to the Closing; however, we anticipate the reduction to be partially offset by continued development of our STACK assets and the addition of the Alta Mesa JV Wells Contribution. |
• | Lease and Plant Operating Expense.Our lease and plant operating expense will be significantly less than our historical results primarily due to the divestiture of Alta Mesa’snon-STACK assets. We anticipate that our future lease and plant operating expenses will remain lower than our historical operations as a result of our centralized operating area that contains new or existing efficient production infrastructure, including saltwater disposal pipelines, managed by experienced operating personnel. |
• | Production and Ad Valorem Taxes.Our production taxes included in our pro forma results of operations included in the financial statements elsewhere in this prospectus are significantly lower than the production taxes included in our historical financial statements as a result of the decline in oil, natural gas and natural gas liquids revenues. In addition, ad valorem taxes are not assessed on our STACK assets. |
• | Depletion, Depreciation and Amortization.Our depletion, depreciation and amortization (“DD&A”) included in our pro forma results of operations is significantly lower than the DD&A in our historical financial statements as a result of proportionately larger reserve volumes and longer reserve life of our STACK assets than the expected production volumes as compared to Alta Mesa’snon-STACK assets. |
• | Impairment Expense.Our impairment expense included in our pro forma results of operations is significantly lower than the impairment expenses in our historical financial statements as almost all of the historical impairment expense was a result of a write-down of Alta Mesa’snon-STACK assets, including the Weeks Island Area, located in Iberia and St. Mary Parishes, Louisiana and natural gas fields in South Texas, East Texas and South Louisiana. |
• | General and Administrative Expense.We will incur certain additional general and administrative expenses (“G&A”) related to being a publicly traded company. In connection with the Closing, we entered into a management services agreement for operational, management and administrative services provided to the Alta Mesa Contributor and its affiliates for the divested non-STACK assets transferred to its former owners under which we will have the right to recoup certain actual expenses. The expense reimbursement will be recorded as an offset to G&A. We will also charge a monthly management fee of $10,000 that will be recorded as Other Revenue in our consolidated statements of operations. |
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• | Provision for Federal Income Taxes.As a corporation, under the Code, we have been subject to federal income taxes at a statutory rate of 35% of pretax earnings. This is a significant change from our historical results since Alta Mesa is a limited partnership and therefore not subject to federal income taxes. We do not expect to report any income tax benefit or expense upon the consummation of the Business Combination. We anticipate a future increase in deferred tax liability for the flow through income from SRII Opco to us based on enacted federal and state tax rates. The tax reform bill passed in December 2017 will reduce the maximum federal income tax rate from 35% to 21%. |
Recent Activity
Contribution from Affiliate and Repayment of Senior Secured Term Loan Facility
On November 10, 2016, High Mesa contributed $300 million in cash from an investment from Bayou City to us, and we used such proceeds to repay (a) all amounts outstanding under Alta Mesa’s second lien senior secured term loan and (b) amounts owed under Alta Mesa’s senior secured revolving credit facility.
Repurchase and Redemption of 9.625% Senior Notes due 2018
On November 30, 2016, Alta Mesa commenced a tender offer for any and all of its outstanding $450 million 9.625% senior notes due 2018 (the “2018 Notes”). The tender offer expired on December 7, 2016 and on December 8, 2016 Alta Mesa paid for the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, Alta Mesa caused to be deposited, with Wells Fargo Bank, National Association, the trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes that remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the 2018 Notes. The Satisfaction and Discharge, among other things, discharged the indenture and Alta Mesa’s obligations thereunder. As a result of the tender offer and redemption, Alta Mesa repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016.
Issuance of 7.875% Senior Notes due 2024
On December 8, 2016, Alta Mesa and its wholly owned subsidiary, Alta Mesa Finance Services Corp. (together with Alta Mesa, the “Issuers”), issued $500.0 million in aggregate principal amount of the 2024 Notes, which resulted in aggregate net proceeds to Alta Mesa of $491.3 million, after deducting commissions and offering expenses. Alta Mesa used the proceeds from the issuance of the 2024 Notes to fund the repurchase and redemption of the 2018 Notes as described above. The remainder of the proceeds was used to repay a portion of Alta Mesa’s indebtedness under its senior secured revolving credit facility.
Amended and Restated Agreement of Limited Partnership
On August 16, 2017, Alta Mesa GP, the Alta Mesa Contributor and the Riverstone Contributor entered into a Sixth Amended and Restated Agreement of Limited Partnership (the “Sixth Amended Partnership Agreement”) of Alta Mesa Holdings, LP. The Sixth Amended Partnership Agreement reflected, among other things, certain changes in the ownership of Alta Mesa, and provided for certain preemptive rights,tag-along rights, and drag-along rights for the limited partners. In connection with the Sixth Amended Partnership Agreement, the existing limited partners of Alta Mesa transferred their interests in Alta Mesa to the Alta Mesa Contributor. The Sixth Amended Partnership Agreement also reflected the admission of the Riverstone Contributor and the Alta Mesa Contributor to the partnership as limited partners, and provided for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK andnon-STACK assets.
The Riverstone Contributor was admitted as a limited partner in connection with its $200 million capital contribution to Alta Mesa on August 17, 2017, in exchange for limited partner interests in Alta Mesa. Alta Mesa used all of the capital contribution to pay down its senior secured revolving credit facility.
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On February 9, 2018, Alta Mesa GP and SRII Opco entered into a Seventh Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) of Alta Mesa Holdings, LP. The Amended Partnership Agreement reflects, among other things, the transfer of ownership of Alta Mesa from the Alta Mesa Contributor and the Riverstone Contributor to SRII Opco.
Amended and Restated Limited Liability Company Agreement
On August 16, 2017, the owners of Alta Mesa GP entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of Alta Mesa GP and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to Alta Mesa GP and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to Alta Mesa GP.
On February 9, 2018, the owners of Alta Mesa GP entered into a Sixth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, reflect that SRII Opco owns all of the Class A Units and 90% of the Class B Units.
Recent Acquisitions and Divestitures
In July 2017, we closed on our acquisition to acquire certain oil and natural gas properties in Oklahoma with an unaffiliated third party for a purchase price of approximately $45.4 million, net of customary post-closing adjustments. The acquired oil and natural gas properties were primarily unproved leasehold. We funded the acquisition with borrowings under our senior secured revolving credit facility.
In September 2017, we acquired approximately $4.6 million of unproved leasehold in Oklahoma. We funded the transaction with cash on hand and accounted for this transaction as an asset acquisition.
In September 2017, we completed a transaction to acquire certain proved oil and natural gas properties from Brown & Borelli, et al (the “B&B Acquisition”) for a purchase price of approximately $3.5 million, net of customary post-closing purchase price adjustments. The fair value of the net assets acquired was approximately $9.1 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $5.3 million.
In April 2017, we completed an acquisition of certain non-STACK proved oil and natural gas properties from Setanta Energy, LLC (the “Setanta” Acquisition) for a purchase price of approximately $0.9 million, net of customary post-closing purchase price adjustments. The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.6 million. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest.
Bayou City Joint Development Agreement
In January 2016, Alta Mesa entered into a joint development agreement with BCE, a fund advised by Bayou City, to fund a portion of its drilling operations and to allow Alta Mesa to accelerate development of its STACK acreage. The drilling program will fund the development of 80 wells, in four tranches of 20 wells each.
On December 31, 2016, High Mesa purchased from BCE and contributed to Alta Mesa interests in 24 producing wells drilled under the joint development agreement. Under the joint development agreement, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding this aggregate limit. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE Interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear their respective proportionate working interest share of
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all subsequent costs and expenses related to such joint well. Since the acquisition of the Alta Mesa JV Wells Contribution, 31 joint wells have been drilled or spudded leaving 49 joint wells to be drilled under the joint development agreement. Of the approximately 120 gross wells we plan to drill in 2017, approximately 32 of such wells are expected to be drilled under the joint development agreement.
Kingfisher County, Oklahoma, Leasehold Acquisition
On July 6, 2015, we acquired approximately 19,000 net acres of undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and is subject to customary purchase price adjustments. The effective date of the acquisition is April 1, 2015. The purchase was funded with borrowings under Alta Mesa’s senior secured revolving credit facility.
Alta Mesa Eagle, LLC Divestiture
On September 30, 2015, we closed the sale of all the membership interests in Alta Mesa Eagle, LLC that held all of our remainingnon-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas to EnerVest Energy Institutional FundXIV-A, L.P. and EnerVest Energy Institutional FundXIV-WIC, L.P. pursuant to a purchase and sale agreement dated September 16, 2015. The effective date of the transaction was July 1, 2015 (the “Eagle Ford Divestiture”).
Pursuant to the agreement, the aggregate cash sale price was $125 million, subject to certain adjustments, consisting of a $118 million initial payment paid at closing, and additional contingent payments of approximately $7 million in the aggregate. As of December 31, 2015, we received net proceeds of $122 million, including $4 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving credit facility.
As of July 1, 2015, our estimated net proved reserves sold were approximately 7.8 MMBOE. As a result of the Eagle Ford Divestiture, we no longer own any assets in the Eagle Ford shale play.
Results of Operations
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
The following table sets forth certain operating information with respect to our oil, natural gas and natural gas liquids operations for the periods indicated:
Nine Months Ended | ||||||||||||||||
September 30, 2017 | September 30, 2016 | Increase (Decrease) | % Change | |||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Summary Operating Information: | ||||||||||||||||
Net Production: | ||||||||||||||||
Oil (MBbls) | 3,533 | 2,985 | 548 | 18 | % | |||||||||||
Natural gas (MMcf) | 14,073 | 10,017 | 4,056 | 40 | % | |||||||||||
Natural gas liquids (MBbls) | 995 | 691 | 304 | 44 | % | |||||||||||
Total oil equivalent (MBOE) | 6,873 | 5,346 | 1,527 | 29 | % | |||||||||||
Average daily oil production (MBOE per day) | 25.2 | 19.5 | 5.7 | 29 | % | |||||||||||
Average Sales Price: | ||||||||||||||||
Oil (per Bbl) including settlements of derivative contracts | $ | 48.25 | $ | 64.60 | $ | (16.35 | ) | (25 | )% | |||||||
Oil (per Bbl) excluding settlements of derivative contracts | 48.01 | 38.78 | 9.23 | 24 | % | |||||||||||
Natural gas (per Mcf) including settlements of derivative contracts | 2.81 | 2.70 | 0.11 | 4 | % |
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Nine Months Ended | ||||||||||||||||
September 30, 2017 | September 30, 2016 | Increase (Decrease) | % Change | |||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Natural gas (per Mcf) excluding settlements of derivative contracts | 2.68 | 2.02 | 0.66 | 33 | % | |||||||||||
Natural gas liquids (per Bbl) including settlements of derivative contracts | 22.14 | 14.67 | 7.47 | 51 | % | |||||||||||
Natural gas liquids (per Bbl) excluding settlements of derivative contracts | 22.93 | 14.62 | 8.31 | 57 | % | |||||||||||
Combined (per BOE) including settlements of derivative contracts | 33.75 | 43.02 | (9.27 | ) | (22 | )% | ||||||||||
Combined (per BOE) excluding settlements of derivative contracts | 33.49 | 27.34 | 6.15 | 22 | % | |||||||||||
Hedging Activities: | ||||||||||||||||
Settlements of derivatives (paid) received, oil | $ | 846 | $ | 77,085 | $ | (76,239 | ) | (99 | )% | |||||||
Settlements of derivatives (paid) received, natural gas | 1,719 | 6,724 | (5,005 | ) | (74 | )% | ||||||||||
Settlements of derivatives (paid), natural gas liquids | (790 | ) | 30 | (820 | ) | N/A | ||||||||||
Summary Financial Information | ||||||||||||||||
Operating Revenues and Other | ||||||||||||||||
Oil | $ | 169,611 | $ | 115,778 | $ | 53,833 | 46 | % | ||||||||
Natural gas | 37,780 | 20,277 | 17,503 | 86 | % | |||||||||||
Natural gas liquids | 22,814 | 10,109 | 12,705 | 126 | % | |||||||||||
Other revenues | 274 | 358 | (84 | ) | (23 | )% | ||||||||||
Gain on sale of assets | — | 3,723 | (3,723 | ) | (100 | )% | ||||||||||
Gain on acquisition of oil and natural gas properties | 6,893 | — | 6,893 | 100 | % | |||||||||||
Gain (loss) on derivative contracts | 38,024 | (23,970 | ) | 61,994 | 259 | % | ||||||||||
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Total Operating Revenues and Other | 275,396 | 126,275 | 149,121 | 118 | % | |||||||||||
Expenses | ||||||||||||||||
Lease and plant operating expense | 49,836 | 45,222 | 4,614 | 10 | % | |||||||||||
Marketing and transportation expense | 21,566 | 8,140 | 13,426 | 165 | % | |||||||||||
Production and ad valorem taxes | 8,812 | 8,021 | 791 | 10 | % | |||||||||||
Workover expense | 5,112 | 3,242 | 1,870 | 58 | % | |||||||||||
Exploration expense | 19,930 | 15,304 | 4,626 | 30 | % | |||||||||||
Depreciation, depletion and amortization expense | 80,082 | 66,857 | 13,225 | 20 | % | |||||||||||
Impairment expense | 29,206 | 14,238 | 14,968 | 105 | % | |||||||||||
Accretion expense | 1,447 | 1,615 | (168 | ) | (10 | )% | ||||||||||
General and administrative expense | 35,534 | 32,909 | 2,625 | 8 | % | |||||||||||
Interest expense, net | 38,189 | 51,581 | (13,392 | ) | (26 | )% | ||||||||||
Provision for state income taxes | 285 | 107 | 178 | 166 | % | |||||||||||
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Net Loss | $ | (14,603 | ) | $ | (120,961 | ) | $ | 106,358 | 88 | % | ||||||
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Average Unit Costs per BOE: | ||||||||||||||||
Lease and plant operating expense | $ | 7.25 | $ | 8.46 | $ | (1.21 | ) | (14 | )% | |||||||
Marketing and transportation expense | 3.14 | 1.52 | 1.62 | 107 | % | |||||||||||
Production and ad valorem tax expense | 1.28 | 1.50 | (0.22 | ) | (15 | )% | ||||||||||
Workover expense | 0.74 | 0.61 | 0.13 | 21 | % | |||||||||||
Exploration expense | 2.90 | 2.86 | 0.04 | 1 | % | |||||||||||
Depreciation, depletion and amortization expense | 11.65 | 12.51 | (0.86 | ) | (7 | )% | ||||||||||
General and administrative expense | 5.17 | 6.16 | (0.99 | ) | (16 | )% |
Revenues
Oil revenues
Oil revenues in the nine months ended September 30, 2017 increased $53.8 million, or 46%, to $169.6 million from $115.8 million in the corresponding period in 2016. The increase in revenue was primarily
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attributable to an increase in average price as well as an increase in production. The average price of oil exclusive of derivative contract settlements increased $9.23 per Bbl, or 24%, in the first nine months of 2017 compared to the first nine months of 2016, resulting in an increase in oil revenues of approximately $32.6 million. When including the effects of derivative contract settlements, the overall price decreased 25% from $64.60 per Bbl in the first nine months of 2016 to $48.25 per Bbl in the first nine months of 2017. The overall price included settlement of oil derivative contracts prior to contract expiry of approximately $0.9 million in the first nine months of 2017 compared to $56.0 million of similar settlements of oil derivative contracts in the corresponding period in 2016. Production increased 548 MBbls, resulting in an increase of $21.2 million in oil revenues. The oil production volume increase was primarily due to new production from wells coming online in the STACK of 943 MBbls, partially offset by a decrease in production in the Weeks Island Area and othernon-STACK areas of 390 MBbls due to a natural decline in production.
Natural gas revenues
Natural gas revenues in the nine months ended September 30, 2017 increased $17.5 million, or 86%, to $37.8 million from $20.3 million in the same period of 2016. The increase in natural gas revenue was primarily attributable to an increase in average price as well as an increase in production during the first nine months of 2017. The average price of natural gas exclusive of derivative contract settlements increased $0.66 per Mcf in the first nine months of 2017, resulting in an increase in natural gas revenues of approximately $9.3 million. When including the effects of derivative contract settlements, the overall price increased 4% from $2.70 per Mcf in the first nine months of 2016 to $2.81 per Mcf in the first nine months of 2017. The overall price in the first nine months of 2016 includes $2.4 million we received related to settlement of several of our natural gas derivative contracts prior to contract expiry. Production increased 4.1 Bcf, resulting in an increase of $8.2 million in natural gas revenues. The natural gas volume increase was primarily due to new production from wells coming online in the STACK of 5.1 Bcf as natural gas is produced in association with oil.
Natural gas liquids revenues
Natural gas liquids revenues increased $12.7 million, or 126%, during the first nine months of 2017 to $22.8 million from $10.1 million in the same period of 2016. The increase in natural gas liquids revenue was attributable to an increase in higher average price as well as an increase in processed volumes during the first nine months of 2017. The average price of natural gas liquids exclusive of derivative contract settlements increased $8.31 per Bbl or 57% in the first nine months of 2017 compared to the first nine months of 2016, resulting in an increase in natural gas liquids revenues of $8.3 million. The overall price including derivative contract settlements increased 51% from $14.67 per Bbl in the first nine months of 2016 to $22.14 per Bbl in the first nine months of 2017. Production increased 304 MBbls from 691 MBbls to 995 MBbls, resulting in an increase of $4.4 million in natural gas liquids revenue. The natural gas liquids volume is predominately in the STACK where natural gas liquids processed volumes increased 321 MBbls.
Gain on sale of assets
Gain on sale of assets was a gain of $3.7 million in the first nine months of 2016, primarily due to the sale of certainnon-core assets.
Gain on acquisition of oil and natural gas properties
Gain on acquisition of oil and natural gas properties was a gain of $6.9 million in the first nine months of 2017, primarily related to the acquisition of STACK oil and natural gas properties. The fair market value of proven reserves exceeded the allocated purchase price of those assets acquired. The acquisition of Brown and Borelli, et al resulted in a bargain purchase gain of approximately $5.3 million as a result of timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increased proved reserves. The Setanta acquisition resulted
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in a bargain purchase gain of approximately $1.6 million as a result of the seller’s financial distress and needing to dispose of the underlying properties for cash in an expedited manner which resulted in a below market purchase price.
Gain (loss) on derivative contracts
Gain (loss) on derivative contracts was a gain of $38.0 million in the first nine months of 2017 as compared to a loss of $24.0 million during the same period in 2016. The fluctuation from period to period was due to the volatility of oil, natural gas and natural gas liquid prices and changes in our outstanding hedge contracts during these periods. The $24.0 million loss in the first nine months of 2016 is inclusive of $83.8 million in settlements received on derivative contracts of which $58.4 million were from settlements of oil and natural gas derivative contracts prior to contract expiry. The $38.0 million gain in the first nine months of 2017 is inclusive of $1.8 million in settlements received on derivative contracts of which $0.9 million were from settlements of oil and natural gas derivative contracts prior to contract expiry.
Expenses
Lease and plant operating expense
Lease and plant operating expense increased $4.6 million or 10% in the first nine months of 2017 as compared to the first nine months of 2016, to $49.8 million from $45.2 million. The increase is primarily due to an increase in compression, chemical, field services and salt water disposal fees of $4.7 million. On a per unit basis, lease and plant operating expense was $7.25 per BOE and $8.46 per BOE in the first nine months of 2017 and 2016, respectively.
Marketing and transportation expense
Marketing and transportation expense increased $13.4 million to $21.5 million in the first nine months of 2017 as compared to $8.1 million in the first nine months of 2016. The increase was primarily due to increased throughput for our properties in the STACK at our processing facility commissioned during the second quarter of 2016. In addition, the increase was due to a higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at our processing facility. On a per unit basis, marketing and transportation expense was $3.14 per BOE and $1.52 per BOE in the first nine months of 2017 and 2016, respectively.
Production and ad valorem taxes
Production and ad valorem taxes increased $0.8 million, or 10%, to $8.8 million in the first nine months of 2017, as compared to $8.0 million in the first nine months of 2016. The increase was primarily due to an increase in production taxes of $1.3 million as a result of the increase in oil, natural gas and natural gas liquids revenues partially offset by a decrease in ad valorem taxes of $0.5 million. Production taxes increased from $6.6 million in the first nine months of 2016 to $7.9 million in the first nine months of 2017.
Workover expense
Workover expense increased $1.9 million during the first nine months of 2017, as compared to the first nine months of 2016. This expense varies depending on activities in the field and is attributable to several properties.
Exploration expense
Exploration expense includes dry hole costs, the costs of our geology department, costs of geological and geophysical (“G&G”) data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration
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expense increased $4.6 million to $19.9 million in the first nine months of 2017, as compared to $15.3 million in the first nine months of 2016. The increase was primarily due to an increase in expired leasehold and settlements of our asset retirement obligation in excess of our estimate of $4.1 million, and an increase of dry hole expense of $2.0 million, partially offset by a decrease in G&G seismic expense of $1.4 million.
Depreciation, depletion and amortization expense
DD&A expense increased from $66.9 million in the first nine months of 2016 to $80.1 million in the first nine months of 2017. DD&A is a function of capitalized costs of proved properties, proved reserves and production by field. In addition, the impairment of proved properties in the third quarter of 2017 and in previous periods and an increase in proved reserves contributed to the lowered depletable base and rate in the first nine months of 2017.
Impairment expense
Impairment expense increased from $14.2 million in the first nine months of 2016 to $29.2 million in the first nine months of 2017. This expense varies with the results of exploratory and development drilling, and also with well performance, declines in commodity price and other factors that may render some fields uneconomic, resulting in impairment. Impairment expense in the first nine months of 2017 and 2016 were primarily write-downs in ournon-STACK areas.
Accretion expense
Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $1.4 million and 1.6 million in each of the first nine months of 2017 and 2016, respectively.
General and administrative expense
G&A expense increased $2.6 million in the first nine months of 2017 to $35.5 million from $32.9��million in the first nine months of 2016. The increase is primarily due to thenon-recurring consulting fees attributable to the Alta Mesa Contribution Agreement during the first nine months of 2017 of approximately $2.5 million and settlement expense of $3.8 million. In addition, information systems maintenance fees increased $1.3 million. These increases were partially offset by a decrease in salary and benefits of $2.1 million including prior period performance bonus accrual adjustments, and a decrease in legal fees of $3.1 million. During the first nine months of 2016, legal fees includednon-recurring tender offer fees of $1.8 million. On a per unit basis, general and administrative expenses were $5.17 per BOE and $6.16 per BOE in the first nine months of 2017 and 2016, respectively.
Interest expense, net
Interest expense, net decreased from $51.6 million in the first nine months of 2016 to $38.2 million in the first nine months of 2017. The interest on Alta Mesa’s senior unsecured notes decreased $3.3 million due to the repurchase and redemption of the 2018 Notes by issuing $500 million aggregate principal amount of the 2024 Notes. In addition, interest including amortization of deferred financing cost on Alta Mesa’s senior secured term loan decreased $9.2 million as Alta Mesa retired its $125 million secured term loan during the fourth quarter of 2016.
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Results of Operations
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
The following table sets forth certain operating information with respect to our oil, natural gas and natural gas liquids operations for the periods indicated:
Year Ended | Increase (Decrease) | % Change | ||||||||||||||
2016 | 2015 | |||||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Summary Operating Information: | ||||||||||||||||
Net Production: | ||||||||||||||||
Oil (MBbls) | 4,001 | 4,203 | (202 | ) | (5 | )% | ||||||||||
Natural gas (MMcf) | 13,959 | 11,900 | 2,059 | 17 | % | |||||||||||
Natural gas liquids (MBbls) | 956 | 678 | 278 | 41 | % | |||||||||||
Total oil equivalent (MBOE) | 7,284 | 6,865 | 419 | 6 | % | |||||||||||
Average daily oil production (MBOE per day) | 19.9 | 18.8 | 1.1 | 6 | % | |||||||||||
Average Sales Price: | ||||||||||||||||
Oil (per Bbl) including settlements of derivative contracts | $ | 61.53 | $ | 67.73 | $ | (6.20 | ) | (9 | )% | |||||||
Oil (per Bbl) excluding settlements of derivative contracts | 40.91 | 47.54 | (6.63 | ) | (14 | )% | ||||||||||
Natural gas (per Mcf) including settlements of derivative contracts | 2.68 | 4.43 | (1.75 | ) | (40 | )% | ||||||||||
Natural gas (per Mcf) excluding settlements of derivative contracts | 2.22 | 2.57 | (0.35 | ) | (14 | )% | ||||||||||
Natural gas liquids (per Bbl) including settlements of derivative contracts | 16.04 | 16.01 | 0.03 | N/A | ||||||||||||
Natural gas liquids (per Bbl) excluding settlements of derivative contracts | 16.38 | 16.01 | 0.37 | 2 | % | |||||||||||
Combined (per BOE) including settlements of derivative contracts | 41.05 | 50.73 | (9.68 | ) | (19 | )% | ||||||||||
Combined (per BOE) excluding settlements of derivative contracts | 28.87 | 35.15 | (6.28 | ) | (18 | )% | ||||||||||
Hedging Activities: | ||||||||||||||||
Settlements of derivatives received, oil | $ | 82,522 | $ | 84,856 | $ | (2,334 | ) | (3 | )% | |||||||
Settlements of derivatives received, natural gas | 6,500 | 22,093 | (15,593 | ) | (71 | )% | ||||||||||
Settlements of derivatives (paid), natural gas liquids | (333 | ) | — | (333 | ) | N/A | ||||||||||
Summary Financial Information | ||||||||||||||||
Operating Revenues and Other | ||||||||||||||||
Oil | $ | 163,677 | $ | 199,799 | $ | (36,122 | ) | (18 | )% | |||||||
Natural gas | 30,953 | 30,621 | 332 | 1 | % | |||||||||||
Natural gas liquids | 15,663 | 10,864 | 4,799 | 44 | % | |||||||||||
Other revenues | 415 | 682 | (267 | ) | (39 | )% | ||||||||||
Gain on sale of assets | 3,542 | 67,781 | (64,239 | ) | (95 | )% | ||||||||||
Gain (loss) on derivative contracts | (40,460 | ) | 124,141 | (164,601 | ) | (133 | )% | |||||||||
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Total Operating Revenues and Other | 173,790 | 433,888 | (260,098 | ) | (60 | )% | ||||||||||
Expenses | ||||||||||||||||
Lease and plant operating expense | 56,893 | 67,706 | (10,813 | ) | (16 | )% | ||||||||||
Marketing and transportation expense | 13,326 | 4,030 | 9,296 | 231 | % | |||||||||||
Production and ad valorem taxes | 10,750 | 15,131 | (4,381 | ) | (29 | )% | ||||||||||
Workover expense | 4,714 | 6,511 | (1,797 | ) | (28 | )% |
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Year Ended | Increase (Decrease) | % Change | ||||||||||||||
2016 | 2015 | |||||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Exploration expense | 24,777 | 42,718 | (17,941 | ) | (42 | )% | ||||||||||
Depreciation, depletion and amortization expense | 92,901 | 143,969 | (51,068 | ) | (35 | )% | ||||||||||
Impairment expense | 16,306 | 176,774 | (160,468 | ) | (91 | )% | ||||||||||
Accretion expense | 2,174 | 2,076 | 98 | 5 | % | |||||||||||
General and administrative expense | 41,758 | 44,454 | (2,696 | ) | (6 | )% | ||||||||||
Interest expense, net | 59,990 | 61,750 | (1,760 | ) | (3 | )% | ||||||||||
Loss on extinguishment of debt | 18,151 | — | 18,151 | N/A | ||||||||||||
Provision for (benefit from) state income taxes | (29 | ) | 562 | (591 | ) | (105 | )% | |||||||||
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Net Loss | $ | (167,921 | ) | $ | (131,793 | ) | $ | (36,128 | ) | (27 | )% | |||||
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Average Unit Costs per BOE: | ||||||||||||||||
Lease and plant operating expense | $ | 7.81 | $ | 9.86 | $ | (2.05 | ) | (21 | )% | |||||||
Marketing and transportation expense | 1.83 | 0.59 | 1.24 | 210 | % | |||||||||||
Production and ad valorem tax expense | 1.48 | 2.20 | (0.72 | ) | (33 | )% | ||||||||||
Workover expense | 0.65 | 0.95 | (0.30 | ) | (32 | )% | ||||||||||
Exploration expense | 3.40 | 6.22 | (2.82 | ) | (45 | )% | ||||||||||
Depreciation, depletion and amortization expense | 12.75 | 20.97 | (8.22 | ) | (39 | )% | ||||||||||
General and administrative expense | 5.73 | 6.48 | (0.75 | ) | (12 | )% |
Revenues
Oil revenues
Oil revenues for the year ended December 31, 2016 decreased $36.1 million, or 18%, to $163.7 million in 2016 from $199.8 million in 2015. The decrease in oil revenue was primarily attributable to lower prices as well as decreased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in oil revenues of approximately $26.5 million. The average price inclusive of settlements of derivative contracts decreased 9% from $67.73 per Bbl in 2015 to $61.53 per Bbl in 2016. A decrease in production of 202 MBbls, or 5% resulted in an approximate $9.6 million decrease in oil revenues. The decrease in oil volumes was primarily due to the Eagle Ford Divestiture in the third quarter of 2015 of 430 MBbls and natural production decline at the Weeks Island Area of 293 MBbls. This decrease was partially offset by new production from the STACK, which increased 564 MBbls, from 2,006 MBbls in 2015 to 2,570 MBbls in 2016.
Natural gas revenues
Natural gas revenues for the year ended December 31, 2016 increased $0.3 million, or 1%, to $30.9 million in 2016 from $30.6 million in 2015. The increase in natural gas revenue was attributable to increased production volumes partially offset by lower prices during 2016. An increase in production of 2.1 Bcf, or 17% resulted in an increase in natural gas revenues of approximately $5.3 million in 2016 as compared to 2015. The increase in natural gas volumes was attributable to new production from the STACK, which increased 3.9 Bcfe, from 4.3 Bcfe in 2015 to 8.2 Bcfe in 2016. This increase was partially offset by natural production decline at the Weeks Island Area of 825 MMcf and the Eagle Ford Divestiture in the third quarter of 2015 of 415 MMcf. The average price of natural gas exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in natural gas revenues of approximately $5.0 million. The average price inclusive of settlements of derivative contracts decreased 40% from $4.43 per Mcf in 2015 to $2.68 per Mcf in 2016.
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Natural gas liquids revenues
Natural gas liquids revenues for the year ended December 31, 2016 increased $4.8 million, or 44% to $15.7 million in 2016 from $10.9 million in 2015. The increase in natural gas liquids revenue was primarily attributable to increased volumes as well as an increase in prices. An increase in volumes of 278 MBbls or 41% resulted in an increase in natural gas liquids revenue of $4.4 million in 2016 as compared to 2015. The increase in natural gas liquid volumes was due primarily to an increase in output in the STACK, which increased 324 MBbls, from 499 MBbls in 2015 to 823 MBbls in 2016. This increase was partially offset by lower volumes due to the Eagle Ford Divestiture in the third quarter of 2015 of 84 MBbls. The average price of natural gas liquids exclusive of settlements of derivative contracts increased 2%, from $16.01 per Bbl in 2015 to $16.38 per Bbl in 2016 resulting in an increase in natural gas liquids revenue of $0.4 million.
Other revenues
Other revenues were $0.4 million during 2016 as compared to $0.7 million during 2015. The decrease was partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.
Gain on sale of assets
Gain on sale of assets was a gain of $3.5 million in 2016 as compared to a gain of $67.8 million in 2015. The sale of South Louisiana properties in 2016 resulted in a gain of $3.5 million. The Eagle Ford Divestiture in the third quarter of 2015 resulted in a gain of $67.6 million.
Gain (loss) on derivative contracts
Gain (loss) on derivative contracts was a loss of $40.5 million inclusive of derivative settlements received of $88.7 million in 2016 as compared to a gain of $124.1 million inclusive of derivative settlements received of $106.9 million in 2015. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedge contracts during these periods.
Expenses
Lease and plant operating expense
Lease and plant operating expense decreased $10.8 million to $56.9 million, or 16%, in 2016 as compared to $67.7 million in 2015. The decrease was primarily due to lower salt water disposal costs, and a decrease in repairs, maintenance, and field services, totaling $10.3 million. On a per unit basis, lease and plant operating expense decreased 21% from $9.86 to $7.81 per BOE for 2015 and 2016, respectively.
Marketing and transportation expense
Marketing and transportation expense increased $9.3 million to $13.3 million in 2016 as compared to $4.0 million in 2015. The increase was primarily in the STACK due to increased throughput at our processing facility beginning in the second quarter of 2016. In addition, the increase was due to a higher marketing and transportation fee charged for utilizing a more efficient facility at our plant. On a per unit basis, marketing and transportation expense increased from $0.59 to $1.83 per BOE for 2015 and 2016, respectively.
Production and ad valorem taxes
Production and ad valorem taxes decreased $4.4 million to $10.7 million, or 29%, for 2016, as compared to $15.1 million for 2015. Production taxes decreased $4.3 million primarily due to the decrease in oil revenues. Ad valorem taxes decreased $0.1 million. On a per unit basis, the production and ad valorem taxes decreased from $2.20 to $1.48 per BOE for 2015 and 2016, respectively.
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Workover expense
Workover expense decreased $1.8 million to $4.7 million from $6.5 million for 2016 and 2015, respectively. This expense varies depending on activities in the field and is attributable to many different properties.
Exploration expense
Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $17.9 million to $24.8 million in 2016 from $42.7 million in 2015. The decrease in exploration expense was primarily due to decreases in dry hole expense of $22.3 million and partially offset by an increase in expired leasehold of $4.6 million. As of December 31, 2016, our property, plant, and equipment balance includes $2.1 million in exploratory well costs which are deferred, pending determination of proved reserves. Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.
Depreciation, depletion and amortization
DD&A decreased $51.1 million to $92.9 million for 2016 as compared to $144.0 million for 2015. On a per unit basis, this expense decreased 39% from $20.97 to $12.75 per BOE for 2015 and 2016, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.
Impairment expense
Impairment expense decreased $160.5 million to $16.3 million in 2016 from $176.8 million in 2015. Thisnon-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates—Impairment” below for more details related to impairment. Certain developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations. The impairments in 2016 were primarily due to write-downs in developed fields, most notably in the Northwest, East Texas and South Louisiana, totaling $15.4 million. The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields, primarily the Weeks Island Area, the STACK, East Texas and South Louisiana, totaling $167.8 million.
Accretion expense
Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.2 million and $2.1 million in 2016 and 2015, respectively.
General and administrative expense
G&A expense decreased $2.7 million to $41.8 million in 2016 from $44.5 million in 2015. The decrease was primarily due to lower litigation settlement expenses recorded in 2016 as compared to 2015 of $5.3 million, partially offset by an increase in salaries, benefits and deferred compensation of $2.6 million in 2016. On a per unit basis, G&A expenses decreased 12% from $6.48 to $5.73 per BOE for 2015 and 2016, respectively.
Interest expense, net
Interest expense, net decreased $1.8 million to $60.0 million in 2016 from $61.8 million in 2015. The decrease was primarily due to the repurchase and redemption of the 2018 Notes during the fourth quarter of
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2016, which decreased interest costs. These decreases were partially offset by an increase in interest expense related to Alta Mesa’s senior secured revolving credit facility and second lien senior secured term loan. The second lien senior secured term loan was repaid in full during the fourth quarter of 2016. Interest expense incurred on Alta Mesa’s borrowings under its senior secured revolving credit facility increased $1.4 million due to an increase in average outstanding balance. Interest expense incurred on Alta Mesa’s borrowing under its second lien senior secured term loan increased $3.0 million as Alta Mesa recognized almost a full year of interest expense and additional amortized deferred financing costs of $0.3 million as compared to the prior year. Alta Mesa entered into the second lien senior secured term loan during the second quarter of 2015.
Loss on extinguishment of debt
Loss on extinguishment of debt was $18.2 million in 2016. During the fourth quarter of 2016, Alta Mesa repurchased an aggregate principal amount of its $450.0 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees. We recognized a loss related to the repurchase of $13.5 million, which included unamortized discount and unamortized deferred financing costs write-offs of $4.1 million. In addition, Alta Mesa repaid all amounts outstanding under the second lien senior secured term loan of $127.7 million, which includes accrued interest and a prepayment premium of $2.5 million. We recognized a loss related to the repayment of $4.7 million, which included unamortized deferred financing costs write-offs of $2.0 million.
Results of Operations
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
The following table sets forth certain operating information with respect to our oil, natural gas and natural gas liquids operations for the periods indicated:
Year Ended | Increase (Decrease) | % Change | ||||||||||||||
2015 | 2014 | |||||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Summary Operating Information: | ||||||||||||||||
Net Production: | ||||||||||||||||
Oil (MBbls) | 4,203 | 3,770 | 433 | 11 | % | |||||||||||
Natural gas (MMcf) | 11,900 | 14,449 | (2,549 | ) | (18 | )% | ||||||||||
Natural gas liquids (MBbls) | 678 | 537 | 141 | 26 | % | |||||||||||
Total oil equivalent (MBOE) | 6,865 | 6,715 | 150 | 2 | % | |||||||||||
Average daily oil production (MBOE per day) | 18.8 | 18.4 | 0.4 | 2 | % | |||||||||||
Average Sales Price: | ||||||||||||||||
Oil (per Bbl) including settlements of derivative contracts | $ | 67.73 | $ | 93.38 | $ | (25.65 | ) | (27 | )% | |||||||
Oil (per Bbl) excluding settlements of derivative contracts | 47.54 | 92.27 | (44.73 | ) | (48 | )% | ||||||||||
Natural gas (per Mcf) including settlements of derivative contracts | 4.43 | 4.87 | (0.44 | ) | (9 | )% | ||||||||||
Natural gas (per Mcf) excluding settlements of derivative contracts | 2.57 | 4.50 | (1.93 | ) | (43 | )% | ||||||||||
Natural gas liquids (per Bbl) excluding settlements of derivative contracts(1) | 16.01 | 34.04 | (18.03 | ) | (53 | )% | ||||||||||
Combined (per BOE) including settlements of derivative contracts | 50.73 | 65.62 | (14.89 | ) | (23 | )% | ||||||||||
Combined (per BOE) excluding settlements of derivative contracts | 35.15 | 64.20 | (29.05 | ) | (45 | )% |
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Year Ended | Increase (Decrease) | % Change | ||||||||||||||
2015 | 2014 | |||||||||||||||
(in thousands, except average sales prices and unit costs) | ||||||||||||||||
Hedging Activities: | ||||||||||||||||
Settlements of derivatives received, oil | $ | 84,856 | $ | 4,187 | $ | 80,669 | 1,927 | % | ||||||||
Settlements of derivatives received, natural gas | 22,093 | 5,306 | 16,787 | 316 | % | |||||||||||
Summary Financial Information | ||||||||||||||||
Operating Revenues and Other | ||||||||||||||||
Oil | $ | 199,799 | $ | 347,842 | $ | (148,043 | ) | (43 | )% | |||||||
Natural gas | 30,621 | 65,002 | (34,381 | ) | (53 | )% | ||||||||||
Natural gas liquids | 10,864 | 18,281 | (7,417 | ) | (41 | )% | ||||||||||
Other revenues | 682 | 1,003 | (321 | ) | (32 | )% | ||||||||||
Gain on sale of assets | 67,781 | 87,520 | (19,739 | ) | (23 | )% | ||||||||||
Gain on derivative contracts | 124,141 | 96,559 | 27,582 | 29 | % | |||||||||||
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Total Operating Revenues and Other | 433,888 | 616,207 | (182,319 | ) | (30 | )% | ||||||||||
Expenses | ||||||||||||||||
Lease and plant operating expense | 67,706 | 64,686 | 3,020 | 5 | % | |||||||||||
Marketing and transportation expense | 4,030 | 9,134 | (5,104 | ) | (56 | )% | ||||||||||
Production and ad valorem taxes | 15,131 | 28,214 | (13,083 | ) | (46 | )% | ||||||||||
Workover expense | 6,511 | 8,961 | (2,450 | ) | (27 | )% | ||||||||||
Exploration expense | 42,718 | 61,912 | (19,194 | ) | (31 | )% | ||||||||||
Depreciation, depletion and amortization expense | 143,969 | 141,804 | 2,165 | 2 | % | |||||||||||
Impairment expense | 176,774 | 74,927 | 101,847 | 136 | % | |||||||||||
Accretion expense | 2,076 | 2,198 | (122 | ) | (6 | )% | ||||||||||
General and administrative expense | 44,454 | 69,198 | (24,744 | ) | (36 | )% | ||||||||||
Interest expense, net | 61,750 | 55,797 | 5,953 | 11 | % | |||||||||||
Provision for state income taxes | 562 | 176 | 386 | 219 | % | |||||||||||
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Net Income (Loss) | $ | (131,793 | ) | $ | 99,200 | $ | (230,993 | ) | (233 | )% | ||||||
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Average Unit Costs per BOE: | ||||||||||||||||
Lease and plant operating expense | $ | 9.86 | $ | 9.63 | $ | 0.23 | 2 | % | ||||||||
Marketing and transportation expense | 0.59 | 1.36 | (0.77 | ) | (57 | )% | ||||||||||
Production and ad valorem tax expense | 2.20 | 4.20 | (2.00 | ) | (48 | )% | ||||||||||
Workover expense | 0.95 | 1.33 | (0.38 | ) | (29 | )% | ||||||||||
Exploration expense | 6.22 | 9.22 | (3.00 | ) | (33 | )% | ||||||||||
Depreciation, depletion and amortization expense | 20.97 | 21.12 | (0.15 | ) | (1 | )% | ||||||||||
General and administrative expense | 6.48 | 10.30 | (3.82 | ) | (37 | )% |
(1) | We entered into derivative contracts for natural gas liquids in the fourth quarter of 2015. The derivative contracts for natural gas liquids became effective in 2016. |
Revenues
Oil revenues
Oil revenues for the year ended December 31, 2015 decreased $148.0 million, or 43%, to $199.8 million from $347.8 million for 2014. The decrease in revenue was attributable to lower average prices partially offset by increased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 48% in 2015; the overall price including settlements of derivative contracts decreased 27% from $93.38 per Bbl in 2014 to $67.73 per Bbl in 2015 resulting in a decrease in oil revenues of approximately $188.0 million,
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partially offset by an increase in production of 433 MBbls, or 11%, resulting in an approximately $40.0 million increase in oil revenues. This increase was primarily due to new production from the STACK, which increased 934 MBbls, from 1,072 MBbls in 2014 to 2,006 MBbls in 2015, partially offset by lower sales volume due to the Eagle Ford Divestiture in the third quarter of 2015 and natural production decline at Weeks Island Area.
Production from our Eagleville field decreased 383 MBbls from 815 MBbls in 2014 to 432 MBbls in 2015, and our Weeks Island Area decreased 61 MBbls from 1,505 MBbls in 2014 to 1,444 MBbls in 2015.
Natural gas revenues
Natural gas revenues for the year ended December 31, 2015 decreased $34.4 million, or 53%, to $30.6 million from $65 million for 2014. The decrease in natural gas revenue was attributable to lower average prices during 2015 as well as decreased production volumes. The average price of natural gas exclusive of settlements of derivative contracts decreased 43% in 2015 resulting in a decrease in natural gas revenues of approximately $22.9 million. The overall price including settlements of derivative contracts decreased 9% from $4.87 per Mcf in 2014 to $4.43 per Mcf in 2015. A decrease in production of 2.5 Bcf, or 18%, resulted in a decrease in natural gas revenues of approximately $11.5 million in 2015 compared to 2014. The decline was due to an emphasis on liquids-rich assets in our capital spending. The decrease in production was attributable to the sale of our remaining working interests in the Hilltop field in the third quarter of 2014. The Hilltop field produced 2.8 Bcf in 2014. In addition, production decreased 3.8 Bcf in East Texas and 0.6 Bcf in South Texas, partially offset by an increase in production in the STACK of 2.2 Bcf.
Natural gas liquids revenues
Natural gas liquids revenues decreased during 2015 to $10.9 million from $18.3 million for 2014. Our average price decreased by 53%, from $34.04 per Bbl in 2014 to $16.01 per Bbl in 2015, partially offset by a 26% increase in volumes from 537 MBbls in 2014 to 678 MBbls in 2015. The decline in prices was due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling. The increase in volume was due primarily to an increase in production in the STACK during 2015 of 184 MBbls, partially offset by lower sales volumes due to the Eagle Ford Divestiture in the third quarter of 2015.
Other revenues
Other revenues were $0.7 million during 2015 as compared to $1.0 million during 2014. The decrease was partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.
Gain on sale of assets
Gain on sale of assets was a gain of $67.8 million in 2015 as compared to a gain of $87.5 million in 2014. The Eagle Ford Divestiture in 2015 resulted in a gain of $67.6 million. The divestiture of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and $15.9 million, respectively.
Gain on derivative contracts
Gain on derivative contracts was a gain of $124.1 million for 2015 as compared to a gain of $96.6 million for 2014. The significant fluctuation from period to period was due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.
Expenses
Lease and plant operating expense
Lease and plant operating expense increased $3.0 million to $67.7 million in 2015 as compared to $64.7 million in 2014. On a per unit basis, lease and plant operating expense increased 2% from $9.63 to $9.86
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per BOE for 2014 and 2015, respectively. The increase was primarily due to higher field services, rental equipment, and compression expense, totaling $6.9 million. The increase was partially offset by a decrease in chemical and fuel usage and salt water disposal of $3.7 million.
Marketing and transportation expense
Marketing and transportation expense decreased $5.1 million to $4.0 million in 2015 from $9.1 million in 2014. The decrease was primarily due to the Eagle Ford Divestiture and the divestiture of the remainder of our Hilltop Field properties during 2014. Hilltop Field properties produced primarily dry gas. On a per unit basis, marketing and transportation expense decreased 57% from $1.36 to $0.59 per BOE for 2014 and 2015, respectively.
Production and ad valorem taxes
Production and ad valorem taxes decreased $13.1 million to $15.1 million, or 46%, for 2015, as compared to $28.2 million for 2014. Production taxes decreased $11.6 million primarily due to the decrease in oil and natural gas revenues. Ad valorem taxes decreased $1.5 million primarily due to the Eagle Ford Divestiture in the third quarter of 2015 and the sale of our Hilltop field in the third quarter of 2014. On a per unit basis, the production and ad valorem taxes decreased 48% from $4.20 to $2.20 per BOE for 2014 and 2015, respectively.
Workover expense
Workover expense decreased $2.5 million to $6.5 million from $9.0 million for 2015 and 2014, respectively. This expense varies depending on activities in the field and is attributable to many different properties.
Exploration expense
Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases and dry holes. Exploration expense decreased $19.2 million to $42.7 million for 2015 from $61.9 million for 2014. The decrease in exploration expense was primarily due to decreases in G&G seismic expenditures of $11.7 million, dry hole expense of $7.6 million and plug and abandonment expenditures of $2.2 million, partially offset by an increase in delay rentals and expired leasehold of $2.2 million. As of December 31, 2015, our property, plant and equipment balance includes $6.0 million in exploratory well costs which are deferred, pending determination of proved reserves. Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.
Depreciation, depletion and amortization
DD&A increased $2.2 million to $144.0 million for 2015 as compared to an expense of $141.8 million for 2014. On a per unit basis, this expense decreased 1% from $21.12 to $20.97 per BOE for 2014 and 2015, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.
Impairment expense
Impairment expense increased $101.9 million to $176.8 million in 2015 from $74.9 million in 2014. Thisnon-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “—Critical Accounting Policies and Estimates—Impairment” below for more details related to impairment. The increase in impairment expense was primarily due to a 47% decrease in the12-month weighted average price for oil and a 41% decrease in the12-month weighted average price for natural gas at December 31, 2015.
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The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields. The primary prospects impaired were in South Texas of approximately $4.1 million and Weeks Island Area of approximately $0.6 million. Several developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations. The most significant of these were in Weeks Island Area of $129.1 million, the STACK of $15.7 million, South Louisiana of $9.4 million and East Texas of $8.9 million.
Accretion expense
Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.1 million and $2.2 million in 2015 and 2014, respectively.
General and administrative expense
G&A expense decreased $24.7 million to $44.5 million in 2015 from $69.2 million in 2014. The decrease was primarily due tonon-recurring capital restructuring expenditures of $13.9 million in 2014, as well as a bonus accrual reduction of $9.9 million and a decrease in deferred compensation expense of $1.8 million in 2015. This decrease was partially offset by an increase in accrued settlement expense of $2.6 million. On a per unit basis, G&A expenses decreased 37% from $10.30 to $6.48 per BOE for 2014 and 2015, respectively.
Interest expense, net
Interest expense, net increased $6.0 million to $61.8 million in 2015 from $55.8 million in 2014. This increase was primarily due to incurred interest expense of $6.2 million and amortization of deferred financing costs of $0.5 million, related to the second lien senior secured term loan that we entered into during 2015. The increase in interest expense was partially offset by an increase in interest income of $0.7 million and lower interest expense of $0.1 million on Alta Mesa’s senior secured revolving credit facility due to a lower average balance outstanding.
Liquidity and Capital Resources
Our principal requirements for capital are to fund ourday-to-day operations, our exploration and development activities and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.
Our 2016 capital budget was primarily focused on the development of our STACK and Weeks Island Area properties through exploitation and development. We spent approximately $226 million in 2016 for exploration and development, including acquisitions, of which over 90% was allocated to our STACK operations and the Weeks Island Areas. The revised capital expenditures for 2016 reflected our plans to drill wells that were funded through the joint development agreement with BCE for the remainder of the year. We reduced our capital expenditures for 2016 from 2015 levels in response to the continued depressed oil prices and to preserve liquidity. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. However, because a large percentage of our acreage is held by production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage. In
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addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved 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 funded our 2016 capital expenditures predominantly with cash flows from operations, drilling and completion of capital funded through our joint development agreement with BCE and capital contributions from an affiliate, supplemented by borrowings under Alta Mesa’s senior secured revolving credit facility and the issuance of the 2024 Notes. In connection with the final sale of preferred stock to Bayou City in October 2016, High Mesa contributed $300 million in cash from the Bayou City investment to us. In November 2016, we repaid all amounts outstanding under our second lien senior secured term loan agreement with such proceeds and paid down amounts owed under Alta Mesa’s senior secured revolving credit facility, providing additional liquidity. We strive to maintain financial flexibility and may access capital markets as necessary to facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we have historically utilized are not available on acceptable terms, we may curtail our capital spending.
We anticipate a capital budget for 2017 of $375.0 million, which includes acquisitions, of which over 95% is allocated to develop our STACK properties. For the nine months ended September 30, 2017, we have been funded approximately $92.7 million from BCE under the joint development agreement. Our 2017 capital expenditure budget is subject to change based on various market conditions, including changes in commodities prices and drilling costs. We have expended approximately $299.5 million of our capital budget through September 30, 2017.
The Riverstone Contributor was admitted as a limited partner in connection with its $200 million capital contribution to Alta Mesa on August 17, 2017, in exchange for limited partner interests in Alta Mesa. Alta Mesa used all of the capital contribution to pay down its senior secured revolving credit facility. In addition, in connection with the Closing, we contributed an additional $400 million to Alta Mesa. We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2017 development drilling activities. 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 and acquire additional properties. We cannot provide any assurances that operations and other needed capital will be available on acceptable terms, or at all.
Senior Notes
On November 30, 2016, Alta Mesa commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016, and on December 8, 2016, Alta Mesa paid for the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, Alta Mesa caused to be deposited with the Trustee funds sufficient to redeem any 2018 Notes that remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed the Satisfaction and Discharge, which, among other things, discharged the indenture and Alta Mesa’s obligations thereunder.
On December 8, 2016, the Issuers issued $500 million in aggregate principal amount of the 2024 Notes to Wells Fargo Securities, LLC and other initial purchasers for resale to certain qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to eligible purchasers outside of the United States pursuant to Regulation S under the Securities Act.
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Alta Mesa’s net proceeds, after deducting offering expenses, were approximately $491 million. Alta Mesa used the net proceeds of the offering as follows:
• | approximately $386 million was used to fund the payment of tendered and accepted 2018 Notes in the tender offer to purchase the $450 million aggregate principal amount of the 2018 Notes, and fees and expenses thereof; |
• | approximately $73 million was used to pay the redemption price of the 2018 Notes that remained outstanding after consummation of the tender offer; and |
• | the remainder was used to repay a portion of Alta Mesa’s existing indebtedness under its senior secured revolving credit facility. |
The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Alta Mesa’s subsidiaries (the “Subsidiary Guarantors”), and will be guaranteed by Alta Mesa’s future domestic restricted subsidiaries, other than certain immaterial subsidiaries. The terms of the 2024 Notes are governed by the indenture, dated as of December 8, 2016 (the “Indenture”), by and among the Issuers, the Subsidiary Guarantors and U.S. Bank, N.A., as trustee.
The 2024 Notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, Alta Mesa may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, Alta Mesa may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of the principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. On and after December 15, 2019, Alta Mesa may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the12-month period beginning on December 15, 2019, 103.938% for the12-month period beginning December 15, 2020, 101.969% for the12-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.
Upon the occurrence of a change of control and, in certain instances, a rating downgrade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services within 90 days thereafter, each holder of the 2024 Notes may require Alta Mesa to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. Because certain existing owners of Alta Mesa and SRII Opco will enter into an amended and restated voting agreement with respect to the voting interests in Alta Mesa GP, the Business Combination is not expected to constitute a change of control under the indenture governing the 2024 Notes. See “Certain Relationships and Related Party Transactions—Voting Agreement.”
The 2024 Notes and the related guarantees are the Issuers’ and the Subsidiary Guarantors’ unsecured, senior obligations. Accordingly, they will rank equal in right of payment to all of Alta Mesa’s existing and future senior indebtedness; senior in right of payment to all of Alta Mesa’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of Alta Mesa’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under Alta Mesa’s senior secured revolving credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of Alta Mesa’s subsidiaries that do not guarantee the 2024 Notes.
The Indenture contains certain covenants limiting the Issuers’ ability and the ability of the restricted subsidiaries to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock
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or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change Alta Mesa’s line of business.
The Indenture contains customary events of default, including:
• | default in any payment of interest on the 2024 Notes when due, continued for 30 days; |
• | default in the payment of principal of or premium, if any, on the 2024 Notes when due; |
• | failure by the Issuers or any Subsidiary Guarantor to comply with their obligations under the Indenture; |
• | default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries; |
• | certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and |
• | failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20.0 million. |
Senior Secured Revolving Credit Facility
On February 9, 2018, Alta Mesa entered into an amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent (the “Alta Mesa Credit Facility”). The Alta Mesa Credit Facility is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base limit. The Alta Mesa Credit Facility does not permit Alta Mesa to borrow funds if at the time of such borrowing it is not in pro forma compliance with its financial covenants. As of February 9, 2018, Alta Mesa has no borrowings under the Alta Mesa Credit Facility and no letters of credit reimbursement obligations.
Principal amounts borrowed are payable on the maturity date. Alta Mesa has a choice of borrowing in Eurodollars or at the base rate, with such borrowings bearing interest, payable quarterly for base rate loans and one month, three month or six month periods for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 page as the London Interbank Offered Rate (“LIBOR”), for deposits in dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 200 to 300 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 100 to 200 basis points. The next scheduled redetermination of Alta Mesa’s borrowing base is on April 1, 2018. Alta Mesa’s borrowing base may be reduced in connection with the next redetermination of its borrowing base. The amounts outstanding under the Alta Mesa Credit Facility are secured by first priority liens on substantially all of Alta Mesa’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the stock of Alta Mesa’s material operating subsidiaries that are guarantors of the Alta Mesa Credit Facility. Additionally, SRII Opco and Alta Mesa GP will pledge their respective limited partner interests in Alta Mesa as security for Alta Mesa’s obligations. If an event of default occurs under the Alta Mesa Credit Facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of the assets of Alta Mesa and its material operating subsidiaries that are guarantors.
The Alta Mesa Credit Facility contains restrictive covenants that may limit Alta Mesa’s ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend its organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Alta Mesa Credit Facility permits Alta Mesa to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement (as defined below).
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The Alta Mesa Credit Facility also requires Alta Mesa to maintain the following two financial ratios:
• | a current ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of Alta Mesa’s consolidated current assets to its consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and |
• | a leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of Alta Mesa’s consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to its consolidated EBITDAX annualized by multiplying EBITDAX for the period of (A) the fiscal quarter ending June 30, 2018 times 4, (B) the two fiscal quarter periods ending September 30, 2018 times 2 and (C) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (D) for each fiscal quarter on or after March 31, 2019, EBITDAX times 4/4, of not greater than 4.0 to 1.0. |
Cash Flows Provided by Operating Activities
Operating activities provided cash of $55.5 million during the nine months ended September 30, 2017 as compared to $7.5 million during the comparable period in 2016, resulting in an increase in cash of $48.0 million. The increase in operating cash flows was attributable to various factors. Cash-based items of net loss including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $10.9 million in the first nine months of 2017. Changes in restricted cash, working capital and other assets and liabilities resulted in an increase of $58.9 million in the first nine months of 2017 as compared to the corresponding period in 2016.
Operating activities provided cash of $131.4 million in 2016, as compared to $144.0 million in 2015. The $12.6 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes. G&A expenses and the cash portion of our interest expense resulted in a net decrease of approximately $36.1 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $27.8 million in cash as compared to having provided $4.5 million in cash in 2015.
Operating activities provided cash of $144.0 million in 2015, as compared to $184.9 million in 2014. The $40.9 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes. G&A expenses and the cash portion of our interest expense resulted in a net decrease of approximately $43.2 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $4.5 million as compared to having provided $2.2 million in cash in 2014.
Cash Flows Provided by (Used in) Investing Activities
Investing activities used cash of $301.1 million during the nine months ended September 30, 2017 as compared to cash used by investing activities of $147.8 million during the comparable period of 2016. Capital expenditures for property and equipment, including acquisitions used cash of $299.5 million and $149.2 million in the first nine months of 2017 and 2016, respectively. Sales of properties provided proceeds of $1.4 million in the first nine months of 2016. In addition, Alta Mesa entered into an interest bearing promissory note receivable with its affiliate Northwest Gas Processing, LLC for approximately $1.5 million during the first nine months of 2017. See Note 14 to our condensed consolidated financial statements entitled “Related Party Transactions.”
Investing activities used cash of $224.3 million for the year ended December 31, 2016 as compared to $105.8 million for the year ended December 31, 2015. The increase in cash used in investing activities was primarily related to proceeds from the sale of property in 2015 of approximately $141.4 million. The increase in cash used for investing activities was partially offset by decreased expenditures for drilling and development and decreased acquisitions in 2016.
Investing activities used cash of $105.8 million for the year ended December 31, 2015 as compared to $189.7 million for the year ended December 31, 2014. The decrease in cash used in investing activities was
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primarily related to decreased expenditures for drilling and development, partially offset by lower proceeds from the sale of assets and an increase in acquisitions. In 2015, the Eagle Ford Divestiture provided net proceeds of approximately $115.0 million and the acquisition of undeveloped leasehold interests in Oklahoma resulted in a use of cash of $47.4 million. In addition, release ofnon-invested funds in the restricted cash account, provided cash of $24.6 million.
Cash Flows Provided by (Used In) Financing Activities
Financing activities provided cash of $242.1 million during the nine months ended September 30, 2017 as compared to $139.6 million during the comparable period in 2016. During the first nine months of 2017, Alta Mesa increased its borrowings under its credit facility by approximately $34.4 million (net), and paid $0.2 million of deferred financing costs related to its credit facility and senior notes. In addition, we received approximately $7.9 million in capital contributions from High Mesa and $200 million in capital contributions from the Riverstone Contributor in connection with its admittance as a limited partner. During the first nine months of 2016, Alta Mesa drew down $141.9 million on its credit facility and deposited the cash in a controlled account pursuant to its credit facility. Alta Mesa paid down its credit facility by approximately $1.5 million and Alta Mesa paid $0.8 million of deferred financing costs related to its credit facility.
Financing activities provided cash of $91.2 million during 2016 as compared to cash used of $30.6 million during 2015, an increase of $121.8 million. During 2016, Alta Mesa used proceeds from the issuance of the 2024 Notes of $500.0 million, capital contributions from an affiliate of $303.5 million and borrowings under its senior secured revolving credit facility of $222.6 million to repay $459.4 million on the 2018 Notes, repay $127.7 million on its second lien senior secured term loan and pay down $333.9 million under its senior secured revolving credit facility. In addition, Alta Mesa incurred $13.7 million of deferred financing costs.
Financing activities used cash of $30.6 million during 2015 as compared to $0.4 million during 2014, an increase of $30.2 million. During 2015, we used proceeds from the Eagle Ford Divestiture of $115.0 million and proceeds from the issuance of the second lien senior secured term loan of $121.0 million, net of issuance cost, to reduce the outstanding balance under Alta Mesa’s senior secured revolving credit facility by $295.0 million. Alta Mesa received $252.5 million in proceeds from long-term debt consisting of $125.0 million under its second lien senior secured term loan and $127.5 million in borrowings under its senior secured revolving credit facility. We made capital distributions of $3.8 million in 2015 as compared to a capital distribution of $0.5 million in 2014. We received capital contributions of $20.0 million from an affiliate in 2015. No contributions were received in 2014. Alta Mesa incurred $4.3 million of deferred financing cost in 2015 related to the borrowing of the second lien senior secured term loan.
Risk Management Activities—Commodity Derivative Instruments
Due to the risk of low oil, natural gas and natural gas liquids prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls and financial basis swap contracts) for a portion of our oil, natural gas and natural gas liquids production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil, natural gas and natural gas liquids prices, and may partially limit our potential gains from future increases in prices. At December 31, 2016, commodity derivative instruments were in place covering approximately 92% of our projected oil production, approximately 72% of our natural gas production and approximately 11% of our natural gas liquids production from proved developed properties for 2017.
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Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2016:
Year Ended December 31, | ||||||||||||||||||||
Total | 2017 | 2018-2019 | 2020-2021 | Thereafter | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Debt | $ | 567,579 | $ | — | $ | — | $ | 67,579 | $ | 500,000 | ||||||||||
Interest(1) | 327,320 | 41,000 | 82,000 | 86,195 | 118,125 | |||||||||||||||
Operating Leases | 11,374 | 3,956 | 2,998 | 3,213 | 1,207 | |||||||||||||||
Drilling rigs(2) | 6,285 | 6,285 | — | — | — | |||||||||||||||
Abandonment liabilities(3) | 61,504 | 376 | 1,094 | 6,989 | 53,045 | |||||||||||||||
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Total | $ | 974,062 | $ | 51,617 | $ | 86,092 | $ | 163,976 | $ | 672,377 | ||||||||||
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(1) | Interest includes interest on the outstanding balance under Alta Mesa’s senior secured revolving credit facility maturing in 2020, payable quarterly; on Alta Mesa’s 2024 Notes, payable semiannually; and on the debt to Alta Mesa’s founder, which is payable with principal, at maturity in 2021. In November 2016, the debt under Alta Mesa’s senior secured revolving credit facility was amended to extend the maturity from April 2018 to November 2020. The weighted average rate on Alta Mesa’s outstanding borrowings as of December 31, 2016 of 4.00% was utilized to calculate the projected interest for Alta Mesa’s senior secured revolving credit facility. Projected obligation amounts are based on the payment schedules for interest and are not presented on an accrual basis. In connection with the Business Combination, Alta Mesa’s debt to its founder was exchanged for equity interest in the Alta Mesa Contributor. |
(2) | The drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed. The drillings rigs are utilized in drilling wells that may or may not be included as part of our joint development agreement with BCE. |
(3) | Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations. |
Off-Balance Sheet Arrangements
As of December 31, 2016, we had no guarantees of third-party obligations. Ouroff-balance sheet obligations include the obligations under operating leases, the $2.2 million contingent properties payment for properties acquired in 2008 and prior years, and the $1.5 million contingent payment if we decide to forego certain drilling activities. We also have bonds posted in the aggregate amount of $24.0 million, primarily to cover future abandonment costs, and $7.6 million in letters of credit provided under our senior secured revolving credit facility. We typically enter into short-term drilling contracts which are customary in the oil and gas industry. We have no otheroff-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.
We have no plans to enter into any additionaloff-balance sheet arrangements in the foreseeable future.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB.
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The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some 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. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP, as well as the most significant estimates and assumptions we makes in applying these policies.
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations (“ARO”), derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.
Property and Equipment
Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Unproved Properties—Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
Exploration Expense—Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.
Proved Oil and Natural Gas Properties—Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized.
Impairment—The capitalized costs of proved oil and natural gas properties are reviewed at least quarterly for impairment following the guidance provided in ASC360-10-35, Property, Plant and Equipment, Subsequent
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Measurement, whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds our fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on aproperty-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.
Depreciation, Depletion and Amortization—DD&A of capitalized costs of proved oil and natural gas properties is computed using theunit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and PUDs. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
Revenue Recognition
We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.
Derivative Financial Instruments
We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815,Derivativesand Hedging,which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets.
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges.
Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.” Cash flows from settlements of derivative contracts are classified as operating cash flows.
Income Taxes
We have elected under the Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal operations taxes is included in the consolidated financial statements.
We are subject to the Texas margin tax, which is considered a state income tax and is included in “Provision for state income tax” on the consolidated statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.
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Acquisitions
Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.
Asset Retirement Obligations
We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410,Asset Retirement and Environmental Obligations.ASC 410 requires that an asset retirement obligation associated with the retirement of a tangible long-lived asset be recognized as a liability 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. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.
Investment
Our investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, our share of earnings or losses of the investment are not included in the consolidated statements of operations.
Distributions from Orion are recognized in current period earnings as declared.
We are a part owner of ARM Energy Management, LLC (“AEM”) with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally withmonth-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee.
Deferred Financing Costs
We capitalize costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASUNo. 2014-09,Revenue from Contracts with Customers.The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASUNo. 2015-14, Deferral of the Effective Date (“ASU2015-14”). ASU2015-14 deferred the effective date of the new revenue standard by one year, making it effective for interim and annual reporting periods beginning after December 15, 2017, except for emerging growth companies that do not elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. We plan to
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adopt the standard during the fourth quarter of 2018 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. We are continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements.
In January 2016, the FASB issued ASUNo. 2016-01,Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
In February 2016, the FASB issued ASU2016-02, Leases (Topic 842),which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) aright-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. We do not plan to adopt the standard early. We enter into lease agreements to support our operations. These lease agreements are for assets such as office space, vehicles, field services and equipment. We continue to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.
In August 2016, the FASB issued ASUNo. 2016-15,Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
In October 2016, the FASB issued ASUNo. 2016-17,Consolidation: Interests Held through Related Parties That Are under Common Control.This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements.
In November 2016, the FASB issued ASU2016-18,Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
In January 2017, the FASB issued ASUNo. 2017-01,Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU2017-01 requires entities to use a screen test to determine when an
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integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Quantitative and Qualitative Disclosures about Market Risk
We are exposed to certain market risks that are inherent in our consolidated financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but we do not enter into derivative agreements for speculative purposes.
We do not designate these derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.
Commodity Price Risk and Hedges
Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for natural gas. We have used, and expect to continue to use, oil, natural gas and natural gas liquids derivative contracts to reduce our exposure to the risks of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated withpre-existing or anticipated sales of oil, natural gas and natural gas liquids.
As of September 30, 2017, we have hedged approximately 73% of our forecasted production from proved developed producing reserves through 2019 at average annual floor prices ranging from $3.18 per MMBtu to $4.43 per MMBtu for natural gas and $50.00 per Bbl to $51.37 per Bbl for oil. Forecasted production from proved reserves is estimated in our 2016 Reserve Report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Please read the disclosures under “Risk Factors—Risks Related to the E&P Business—Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”
The fair value of our commodity derivative contracts at September 30, 2017 was a net asset of $11.9 million. A 10% increase or decrease in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity derivative contracts of approximately $23.1 million (decrease in value) or $21.9 million (increase in value), respectively, as of September 30, 2017.
Counterparty and Customer Credit Risk
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our 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.
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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 Rates
We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts. A 1% increase in interest rates would increase annual interest expense on our variable rate debt by approximately $0.8 million, based on the balance outstanding as of September 30, 2017.
Inflation
Inflation in the U.S. 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, 2016 or 2015. Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and G&A expenses.
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Directors and Executive Officers
Set forth below are the names, ages and positions of each of our directors and officers:
Name | Age | Position | ||
James T. Hackett(1) | 63 | Executive Chairman of the Board and Chief Operating Officer—Midstream | ||
Harlan H. Chappelle(2) | 61 | Chief Executive Officer and Director | ||
Michael E. Ellis(2) | 61 | Chief Operating Officer—Upstream and Director | ||
Michael A. McCabe | 62 | Chief Financial Officer | ||
David Murrell | 55 | Vice President of Land and Business Development | ||
Homer “Gene” Cole | 53 | Vice President and Chief Technology Officer | ||
Ronald J. Smith | 58 | Vice President and Chief Accounting Officer | ||
David M. Leuschen(1) | 66 | Director | ||
Pierre F. Lapeyre, Jr.(1) | 55 | Director | ||
William W. McMullen(2) | 32 | Director | ||
Don Dimitrievich(2) | 46 | Director | ||
William D. Gutermuth | 66 | Director | ||
Jeffrey H. Tepper | 51 | Director | ||
Diana J. Walters | 54 | Director | ||
Donald R. Sinclair | 60 | Director |
(1) | As a result of the Riverstone Contributor’s ownership of our Series B Preferred Stock, the Riverstone Contributor is entitled to nominate directors to our board of directors for a period of up to five years following the Closing based on its and its affiliates, beneficial ownership of our Class A Common Stock. The Riverstone Contributor is entitled to nominate three directors to our board of directors, one of whom will be the Chairman of the Board, for so long as it and its affiliates own at least 15% of the outstanding Class A Common Stock. The vote of the Riverstone Contributor is the only vote required to elect such nominee to our board. |
(2) | As a result of each of Bayou City, HPS and AM Managements owning a share of our Series A Preferred Stock, each of Bayou City, HPS and AM Management are entitled to nominate directors to our board of directors for a period of up to five years following the Closing based on their and their respective affiliates, beneficial ownership of our Class A Common Stock. For so long as (i) Bayou City and its affiliates own at least 10% of the outstanding Class A Common Stock, Bayou City is entitled to nominate one director who must be independent for NASDAQ purposes (unless the director to be nominated is William W. McMullen who need not be independent), (ii) HPS and its affiliates own at least 10% of the outstanding Class A Common Stock, HPS is entitled to nominate one director who must be independent for NASDAQ purposes and (iii) AM Management and its affiliates own at least 10% of the outstanding Class A Common Stock, AM Management is entitled to nominate two directors who need not be independent for NASDAQ purposes. |
James T. Hackett became our Executive Chairman of the board of directors and Chief Operating Officer—Midstream immediately following the Closing. He has previously served as our Chief Executive Officer and director since March 2017. Mr. Hackett is a partner at Riverstone. Prior to joining Riverstone in 2013, Mr. Hackett served as the Chairman of the Board from 2006 to 2013 and the Chief Executive Officer from 2003 to 2012 of Anadarko Petroleum Corporation. Before joining Anadarko, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation, following its merger with Ocean Energy, where he had served as Chairman, President, and Chief Executive Officer. Mr. Hackett has held senior positions at Seagull, Duke Energy, and Pan Energy. He also held positions in engineering, finance and marketing in the midstream, oil field services, and power sectors of the energy industry. Mr. Hackett serves on the Board of Directors of Enterprise Products Holdings, LLC, Fluor Corporation (NYSE: FLR), National Oilwell Varco, Inc. (NYSE: NOV), Sierra Oil and Gas and Talen Energy Corporation and Crimson Resources. Mr. Hackett is a former
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Chairman of the Board of the Federal Reserve Bank of Dallas. Mr. Hackett received a Bachelor of Science degree from the University of Illinois in 1975 and an MBA and MTS from Harvard Business School in 1979 and 2016, respectively. Mr. Hackett was selected to serve on the board of directors due to his significant leadership experience and his extensive experience in the energy industry.
Harlan H. Chappelle became our Chief Executive Officer immediately following the Closing. He has previously served as the President, CEO and director of Alta Mesa since November 2004. Mr. Chappelle has over 30 years of experience in field operations, engineering, management, marketing and trading, acquisitions and divestitures and fieldre-development. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin. Mr. Chappelle’s experience as our Chief Executive Officer since 2004 and over 30 years of experience in the oil and gas industry uniquely qualify him to serve on our board of directors.
Michael E. Ellisbecame our Chief Operating Officer—Upstream immediately following the Closing. Mr. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco and previously served as our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis managed allday-to-day engineering and field operations of Alta Mesa. He built our asset base by starting with smallearn-in exploitation projects, then progressively grew Alta Mesa with successive acquisitions of fields from major oil companies and consistent success in exploration and development drilling. He has over 30 years’ experience in management, engineering, exploration and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University. Because of his broad knowledge of, and experience with, oil and gas exploration and production, we believe Mr. Ellis is well qualified to serve on our board of directors.
Michael A. McCabebecame our Chief Financial Officer immediately following the Closing. Mr. McCabe has served as Chief Financial officer and Vice President of Alta Mesa since 2006. Mr. McCabe joined Alta Mesa in September 2006 and became a director in March 2014. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. He has served in senior positions with Bank of Tokyo, Bank of New England and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Master of Science in Chemical Engineering from Purdue University and a Master of Business Administration in Financial Management from Pace University.
David Murrellhas served as our Vice President, Land and Business Development since 2006. Mr. Murrell has over 30 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of division order analysts, lease analysts, landmen, and field representatives that has facilitated our growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma and is a Certified Professional Landman through the Association of Professional Landmen.
Homer “Gene” Colejoined Alta Mesa in 2007 and has served in the position of Vice President and Chief Technical Officer since August 2015 and became a director in August 2015. Mr. Cole has over 25 years of extensive domestic and international oilfield experience in management, well completions and well stimulation design and execution. He started his career with Schlumberger Dowell as a Field Engineer and served from 1986 to 2007 in numerous positions of increasing responsibility with Schlumberger in the areas of field operations, engineering and management. He has a Bachelor of Science in Petroleum Engineering from Marietta College.
Ronald J. Smith. Mr. Smith has been appointed to service as our Vice President and Chief Accounting Officer effective upon the Closing. Mr. Smith has over 35 years of accounting experience, primarily in the energy industry. Mr. Smith served as the Chief Accounting Officer of Alta Mesa from 2015 to the Closing. Mr. Smith began working for Alta Mesa in 2008 as the Controller. Mr. Smith has served in numerous senior level management positions including positions with Calpine Corporation and Mariner Energy. Mr. Smith holds a Bachelor of Science in Accounting from Robert Morris University, an MBA in Finance from the University of Houston and is a Certified Public Accountant.
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David M. Leuschenbecame a director immediately following the Closing. Mr. Leuschen is a Founder of Riverstone and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman Sachs and founder and head of the Goldman Sachs Global Energy and Power Group. Mr. Leuschen joined Goldman Sachs in 1977, became head of the Global Energy and Power Group in 1985, became a Partner of that firm in 1986 and remained with Goldman Sachs until leaving to found Riverstone in 2000. Mr. Leuschen also served as Chairman of the Goldman Sachs Energy Investment Committee, where he was responsible for screening potential capital commitments by Goldman Sachs in the energy and power industry and was responsible for establishing and managing the firm’s relationships with senior executives from leading companies in all segments of the energy and power industry. Mr. Leuschen serves as anon-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013, anon-executive board member of Centennial Resource Development, Inc. since October 2016 and serves on the boards of directors or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates. In 2007, Mr. Leuschen, along with Riverstone and The Carlyle Group (“Carlyle”), became the subject of an industry-wide inquiry by the Office of the Attorney General of the State of New York (the “Attorney General”) relating to the use of placement agents in connection with investments by the New York State Common Retirement Fund (“NYCRF”) in certain funds, including funds that were jointly developed by Riverstone and Carlyle. In June 2009, Riverstone entered into an Assurance of Discontinuance with the Attorney General to resolve the matter and agreed to make a restitution payment of $30 million to the New York State Office of the Attorney General for the benefit of NYCRF. Mr. Leuschen also entered into an Assurance of Discontinuance with the Attorney General in December 2009 and agreed that Riverstone and/or Mr. Leuschen would make a restitution payment of $20 million to the New York State Office of the Attorney General for the benefit of NYCRF. Mr. Leuschen has received an MBA from Dartmouth’s Amos Tuck School of Business and an A.B. degree from Dartmouth College. Mr. Leuschen was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry.
Pierre F. Lapeyre, Jr.became a director immediately following the Closing. Mr. Lapeyre is a Founder of Riverstone and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Lapeyre was a Managing Director of Goldman Sachs in its Global Energy and Power Group. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his14-year investment banking career focused on energy and power, particularly the midstream, upstream and energy service sectors. Mr. Lapeyre serves as anon-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013, anon-executive board member of Centennial Resource Development, Inc. since October 2016 and serves on the boards of directors or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates. He has an MBA from the University of North Carolina at Chapel Hill and a B.S. in Finance and Economics from the University of Kentucky. Mr. Lapeyre was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry.
William W. McMullenbecame a director immediately following the Closing. Mr. McMullen is the founder and managing partner of Bayou City Energy (“BCE”), an oil and gas focused private equity firm based in Houston, Texas. Mr. McMullen founded BCE in 2015 after successfully managing a smaller private equity vehicle, Bayou City Energy Partners (“BCEP”), focused on investments in the oil and gas sector. Prior to BCEP, Mr. McMullen served as Vice President at White Deer Energy, an oil and gas focused private equity firm. Before White Deer Energy, Mr. McMullen served as an Associate at Denham Capital. Prior to Denham Capital, Mr. McMullen served as an Analyst in UBS Investment Bank’s Global Energy group. Mr. McMullen earned his Bachelor’s degree in Economics, with Honors, from Harvard University. Because of his broad knowledge of, and experience with, oil and gas investments, we believe Mr. McMullen is well qualified to serve on our board of directors.
Don Dimitrievich became a director of the Company immediately following the Closing. Mr. Dimitrievich is a Managing Director at HPS and is responsible for the energy and power portfolio. Prior to joining HPS in 2012, Mr. Dimitrievich was a Managing Director of Citi Credit Opportunities, a credit-focused principal investment group. At Citi Credit Opportunities, Mr. Dimitrievich oversaw the energy and power portfolio and
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invested in mezzanine, special situation and equityco-investments, and secondary market opportunities. Prior to joining Citi, Mr. Dimitrievich worked in the New York office of Skadden, Arps, Slate, Meagher & Flom LLP from 1998 to 2004 focusing on energy M&A and capital markets transactions. Mr. Dimitrievich has a law degree magna cum laude from McGill University in Montreal, Canada and earned a chemical engineering degree with Great Distinction from Queen’s University in Kingston, Canada. Mr. Dimitrievich currently serves on the following Boards: Blue Ridge Mountain Resources, Inc., Expro International Group Holdings Ltd., Glacier Oil & Gas Corp., Marquis Resources, LLC and Upstream Exploration LLC. Mr. Dimitrievich was selected to serve on the board of directors due to his significant mergers and acquisitions, financing and investing experience in the energy and power industry.
William D. Gutermuth has been a director since March 2017. Mr. Gutermuth is the Founder and Chairman of Bluegrass Capital LLC, a privately owned investment and consulting firm. Since January 1, 2015, he has devoted substantially all of his professional time and energies to Bluegrass Capital. Prior to that, Mr. Gutermuth was an equity partner at Bracewell & Giuliani LLP and its predecessor firm, Bracewell & Patterson, LLP, where he practiced corporate and transactional law for almost 35 years. Mr. Gutermuth’s legal career focused principally on mergers and acquisitions, particularly in the energy industry, as well as most aspects of corporate finance and corporate governance. Mr. Gutermuth chaired Bracewell & Giuliani’s worldwide Corporate and Securities Practice from 1999 to 2005 and served as a member of the Business Group Executive Committee from 2005 to 2007, as well as serving in other leadership positions within the law firm throughout his career. Mr. Gutermuth served as a director of Main Street Capital Corporation (NYSE: MAIN), a publicly traded business development company, from 2007 to 2012 and on the Compensation and Nominating and Governance Committees during his tenure as a director. Mr. Gutermuth also served as a director of Silver Run Acquisition Corporation (NASDAQ: SRAQ) from its inception in November 2015 until the completion of its acquisition of Centennial Resource Production, LLC in October 2016. Mr. Gutermuth holds a B.S. in Political Science from Vanderbilt University and a J.D. from Vanderbilt University School of Law. Mr. Gutermuth was selected to serve on the board of directors due to his significant leadership experience and his extensive merger and acquisition experience.
Jeffrey H. Tepper has been a director since March 2017. Mr. Tepper is a Founder of JHT Advisors LLC, a mergers and acquisitions advisory and investment firm. From 1990 to 2013, Mr. Tepper served in a variety of senior management and operating roles at the investment bank Gleacher & Company, Inc. and its predecessors and affiliates (“Gleacher”). Mr. Tepper is experienced in mergers and acquisitions, corporate finance, leveraged finance and asset management. Mr. Tepper was Head of Investment Banking and a member of the Management Committee while at Gleacher. Mr. Tepper led numerous investment banking transactions on behalf of clients in a variety of industries but with a specialty in financial services and asset management. Mr. Tepper also served as Gleacher’s Chief Operating Officer, overseeing operations, compliance, technology and financial reporting. In 2001, Mr. Tepperco-founded Gleacher’s asset management activities and served as President. Mr. Tepper served on the Investment Committees of Gleacher Mezzanine and Gleacher Fund Advisors. Between 1997 and 1999, Mr. Tepper served as Managing Director of and Chief Operating Officer of Gleacher NatWest Inc. (a predecessor to Gleacher Partners). Mr. Tepper was part of the senior management team of Gleacher NatWest with oversight responsibility for middle-market senior and subordinated debt, high-yield and equity principal activities. Between 1987 and 1990, Mr. Tepper was employed by Morgan Stanley & Co. as a financial analyst in the mergers and acquisitions and merchant banking departments. Mr. Tepper also served as a director of Silver Run Acquisition Corporation (NASDAQ: SRAQ) from its inception in November 2015 until the completion of its acquisition of Centennial Resource Production, LLC in October 2016 and has served as a director of Centennial Resource Development, Inc. (NASDAQ: CDEV) since October 2016. Mr. Tepper received an MBA from Columbia Business School and a B.S. in Economics from The Wharton School of the University of Pennsylvania with concentrations in finance and accounting. Mr. Tepper was selected to serve on the board of directors due to his significant investment and financial experience.
Diana J. Walters has been a director since March 2017. Ms. Walters has 30 years of experience in the natural resources sector, as an investment manager and equity investor, as an investment banker and in operating
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roles. Ms. Walters has been the owner and sole manager of 575 Grant, LLC, a company that provides advisory services in the field of natural resources, since 2014. She served as the President and Chief Executive Officer of Liberty Metals & Mining Holdings, LLC and a member of senior management of Liberty Mutual Asset Management from January 2010 to September 2014. She was a Managing Partner of Eland Capital, LLC, a natural resources advisory firm founded by her, from 2007 to 2010. Ms. Walters has extensive investment experience with both debt and equity through various previous leadership roles at Credit Suisse, HSBC and other firms. She also served previously as Chief Financial Officer of Tatham Offshore Inc., an independent oil and gas company with assets in the Gulf of Mexico. Ms. Walters also served as a director of Silver Run Acquisition Corporation (NASDAQ: SRAQ) from its inception in November 2015 until the completion of its acquisition of Centennial Resource Production, LLC in October 2016. Ms. Walters currently serves on the board of directors of Platinum Group Metals (NYSE: PLG) and Electrum Special Acquisition Corporation (NASDAQ: ELECU). Ms. Walters graduated with Honors from the University of Texas at Austin with a B.A. in Plan II Liberal Arts and an M.A. in Energy and Mineral Resources. Ms. Walters was selected to serve on the board of directors due to her significant investment and operating experience in the energy industry.
Donald R. Sinclair became become a director immediately following the Closing. Mr. Sinclair has over 30 years of experience in the oil and gas industry, with a focus on marketing and trading, particularly in the midstream sector. Mr. Sinclair currently serves as the Chairman of the Board of Directors and President of WTX Pumping Services LLC. He also currently serves as a senior advisor to Anadarko Petroleum Corporation and as a senior advisor to Western Gas Equity Holdings, LLC (“WES GP”), the general partner of Western Gas Equity Partners LP. From 2009 to 2017, Mr. Sinclair served as the President and Chief Executive Officer of WES GP and as a member of the board of directors of WES GP. From 2010 to 2016, he also served as the Vice President and Senior Vice President of Anadarko Petroleum Corporation. In 2003, Mr. Sinclairco-founded Ceritas Energy, LLC (“Ceritas”), and served as the President and Chief Executive Officer of Ceritas from 2003 to 2009. From 1998 to 2003, Mr. Sinclair was involved in energy industry consulting and the management of personal business interests. From 1997 to 1998, he served as the President of Duke Energy Trading and Marketing LLC (“Duke”). Prior to joining Duke, Mr. Sinclair served as Senior Vice President of Tenneco Energy, a unit of Tenneco Inc. (“Tenneco”), and as President of Tenneco Energy Resources Corporation. Prior to joining Tenneco, Mr. Sinclair also served for eight years in various officer positions with Dynegy Inc. (formerly NGC Corporation), including as Senior Vice President and Chief Risk Officer, during which time he was in charge of all risk management activities and commercial operations. Mr. Sinclair earned a Bachelor of Business Administration degree from Texas Tech University. Mr. Sinclair was selected to serve on the board of directors due to his significant leadership experience and his extensive investment experience in the oil and gas industry.
Board of Directors and Terms of Office of Officers and Directors
On the Closing Date, in connection with the Business Combination, the size of the Company’s board of directors (the “Board”) was increased from four members to eleven members. Messrs. William D. Gutermuth, Donald R. Sinclair and David M. Leuschen were appointed to serve as Class I directors, with terms expiring at the Company’s annual meeting of stockholders in 2018; Messrs. Jeffrey H. Tepper, Michael E. Ellis and Pierre F. Lapeyre, Jr. and Ms. Diana J. Walters were appointed to serve as Class II directors, with a term expiring at the Company’s annual meeting of stockholders in 2019; and Messrs. James T. Hackett, Harlan H. Chappelle, Don Dimitrievich and William W. McMullen were appointed to serve as Class III directors, with a term expiring at the Company’s annual meeting of stockholders in 2020.
Since the beginning of the Company’s last fiscal year through the present, there have been no transactions with the Company, and there are currently no proposed transactions with the Company, in which the amount involved exceeds $120,000 and in which Mr. Sinclair had or will have a direct or indirect material interest within the meaning of Item 404(a) of RegulationS-K. No arrangement or understanding exists between Mr. Sinclair and any other person pursuant to which Mr. Sinclair was selected as a director of the Company.
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Independence of Directors
Under the listing rules of NASDAQ, we are required to have a majority of independent directors serving on our Board. The Company’s Board has determined that Ms. Diana J. Walters and Messrs. Don Dimitrievich, William D. Gutermuth, Jeffrey H. Tepper, Donald R. Sinclair, David M. Leuschen and Pierre F. Lapeyre, Jr. are independent within the meaning of NASDAQ Rule 5605(a)(2).
Bayou City, HPS and AM Management own the only outstanding shares of our Series A Preferred Stock. For so long as the Series A Preferred Stock remains outstanding, the holders of the Series A Preferred Stock are entitled to nominate and elect directors to our board of directors for a period of five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Bayou City and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ (unless the director to be nominated is William W. McMullen who need not be independent) | |
HPS and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ | |
AM Management and its affiliates | ||
• at least 10% | two directors who need not be independent for purposes of the listing rules of NASDAQ | |
• less than 10% but at least 5% and either Hal Chappelle or Michael Ellis is a member of our management | one director who need not be independent for purposes of the listing rules of NASDAQ |
The Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock. For so long as the Series B Preferred Stock remains outstanding, the holder of the Series B Preferred Stock is entitled to nominate and elect directors to our board of directors for a period of five years following the Closing based on its and its affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Riverstone Contributor and its affiliates | ||
• at least 15% | three directors (one of whom will be the Chairman of the Board) | |
• less than 15% but at least 10% | two directors (one of whom will be the Chairman of the Board) | |
• less than 10% but at least 5% | one director (who may be the Chairman of the Board if such person is Jim Hackett) |
Officers are appointed by the board of directors and serve at discretion of the board, rather than for specific terms of office.
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Board Committees
Following the Closing, the standing committees of the Company’s Board consist of an audit committee (the “Audit Committee”), a compensation committee (the “Compensation Committee”) and a nominating and corporate governance committee (the “Nominating and Corporate Governance Committee”). Each of the committees reports to the Board. The composition, duties and responsibilities of these committees are set forth below.
Audit Committee.The principal functions of the Company’s Audit Committee are detailed in the Company’s Audit Committee charter, which is available on the Company’s website, and include:
• | the appointment, compensation, retention, replacement, and oversight of the work of the independent auditors and any other independent registered public accounting firm engaged by the Company; |
• | pre-approving all audit and permittednon-audit services to be provided by the independent auditors or any other registered public accounting firm engaged by the Company, and establishingpre-approval policies and procedures; |
• | reviewing and discussing with the independent auditors all relationships the auditors have with the Company in order to evaluate their continued independence; |
• | setting clear hiring policies for employees or former employees of the independent auditors; |
• | setting clear policies for audit partner rotation in compliance with applicable laws and regulations; |
• | obtaining and reviewing a report, at least annually, from the independent auditors describing (i) the independent auditor’s internal quality-control procedures and (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the audit firm, or by any inquiry or investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the firm and any steps taken to deal with such issues; |
• | reviewing and approving any related party transaction required to be disclosed pursuant to Item 404 of RegulationS-K promulgated by the SEC prior to us entering into such transaction; and |
• | reviewing with management, the independent auditors and our legal advisors, as appropriate, any legal, regulatory or compliance matters, including any correspondence with regulators or government agencies and any employee complaints or published reports that raise material issues regarding our financial statements or accounting policies and any significant changes in accounting standards or rules promulgated by the Financial Accounting Standards Board, the SEC or other regulatory authorities. |
Under the NASDAQ listing standards and applicable SEC rules, the Company is required to have at least three members of the Audit Committee, all of whom must be independent. Following the Closing, our Audit Committee consists of Messrs. William D. Gutermuth and Jeffrey H. Tepper and Ms. Diana J. Walters, with Ms. Diana J. Walters serving as the Chair. We believe that Messrs. William D. Gutermuth and Jeffrey H. Tepper and Ms. Diana J. Walters qualify as independent directors according to the rules and regulations of the SEC with respect to audit committee membership. We also believe that Diana J. Walters qualifies as our “audit committee financial expert,” as such term is defined in Item 401(h) of RegulationS-K.
Compensation Committee.The principal functions of the Company’s Compensation Committee are detailed in the Company’s Compensation Committee charter, which is available on the Company’s website, and include:
• | reviewing and approving on an annual basis the corporate goals and objectives relevant to the Company’s Chief Executive Officer’s compensation, evaluating its Chief Executive Officer’s performance in light of such goals and objectives and determining and approving the remuneration (if any) of its Chief Executive Officer based on such evaluation; |
• | reviewing and approving on an annual basis the compensation of all of the Company’s other officers; |
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• | reviewing on an annual basis the Company’s executive compensation policies and plans; |
• | implementing and administering the Company’s incentive compensation equity-based remuneration plans; |
• | assisting management in complying with the Company’s proxy statement and annual report disclosure requirements; |
• | approving all special perquisites, special cash payments and other special compensation and benefit arrangements for the Company’s officers and employees; |
• | if required, producing a report on executive compensation to be included in the Company’s annual proxy statement; and |
• | reviewing, evaluating and recommending changes, if appropriate, to the remuneration for directors. |
Under the NASDAQ listing standards, the Company is required to have a Compensation Committee, all of whom must be independent. Following the Closing, our Compensation Committee consists of Messrs. Donald R. Sinclair and Jeffrey H. Tepper and Ms. Diana J. Walters, with Mr. Donald R. Sinclair serving as the Chair. We believe that Messrs. Donald R. Sinclair and Jeffrey H. Tepper and Ms. Diana J. Walters qualify as independent directors according to the rules and regulations of the NASDAQ with respect to compensation committee membership.
Nominating and Corporate Governance Committee.The principal functions of the Company’s Nominating and Corporate Governance Committee aredetailed in the Company’s Nominating and Corporate Governance Committeecharter, which is available on the Company’s website, and include:
• | assisting the Board in identifying individuals qualified to become members of the Board, consistent with criteria approved by the Board; |
• | recommending director nominees for election or for appointment to fill vacancies; |
• | recommending the election of officer candidates; |
• | monitoring the independence of Board members; |
• | ensuring the availability of director education programs; and |
• | advising the Board about appropriate composition of the Board and its committees. |
The Nominating and Corporate Governance Committee also develops and recommends to the Board corporate governance principles and practices and assists in implementing them, including conducting a regular review of our corporate governance principles and practices. The Nominating and Corporate Governance Committee oversees the annual performance evaluation of the Board and the committees of the Board and makes a report to the Board on succession planning.
Following the Closing, our Nominating and Corporate Governance Committee consists of Messrs. Donald R. Sinclair, Jeffrey H. Tepper and Ms. Diana J. Walters, with Mr. Jeffrey H. Tepper serving as the Chair.
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The following disclosure concerns thepre-Business Combination compensation of our executive officers and directors and describes the material elements of compensation for our named executive officers (“NEOs”) for 2017.
Objectives of Our Compensation Program
Our Board of Directors is responsible for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.
Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results. In addition, our program is designed to achieve the following objectives:
• | attract and retain highly qualified executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations; |
• | provide total compensation that is justified by individual performance; and |
• | reward our executives for their contributions to our overall performance as well as for their individual performance. |
What Our Compensation Program is Designed to Reward
Our strategy is to enhance partners’ value by increasing reserves, cash flow and production in an economically efficient manner by optimizing our drilling and completion techniques. Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy, such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.
Elements of Our Compensation Program and Why We Pay Each Element
To accomplish our objectives, our compensation program is comprised primarily of the following elements: base salary, cash bonus, long-term incentives and benefits.
We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.
We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.
We provide a supplemental executive retirement plan to certain key employees, including all our executive officers, to provide additional flexibility and tax planning advantages to them. In addition, the retirement benefits enhance employee compensation on a discretionary basis and encourage their continued service to us.
We grant performance appreciation rights units (“PARs”) as long term compensation to certain key employees, including our executive officers, who make significant contributions to us. The PARs are payable on
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a fixed determination date which is generally between five and 10 years from the grant date of the award or in the event of a Liquidity Event (as defined in the PARs Plan), and therefore, provide the grantee with a significant interest in us tied to long-term performance. Following the Business Combination, we will cease issuing PARs.
We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees. In 2013, we introduced a deferred compensation plan offered to all employees, to provide flexibility and tax planning advantages to them.
How We Determine Each Element of Compensation
In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2017 compensation.
Messrs. Ellis, Chappelle, McCabe and Murrell are parties to employment agreements with Alta Mesa Services, L.P. a wholly owned subsidiary of ours (“Alta Mesa Services”). The employment agreements automatically renew annually, subject to prior notice of cancellation by either Alta Mesa Services or the executive. These employment agreements establish minimum base salaries for each officer. On March 25, 2014, these employment agreements were amended and restated and the salaries for the officers were set at $485,000, $485,000, $435,000, and $360,000 per annum, to Messrs. Ellis, Chappelle, McCabe and Murrell, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary only if performance criteria set by our Board for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses and participation in employee benefit plans.
Base salary. In reviewing base salaries, our Board takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors our Board considers include individual achievements, our performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the review and determination of their respective base salaries. For 2017, our Board set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively, which were unchanged from their 2016 base salaries. In addition, our Board determined Mr. Murrell’s and Mr. Cole’s salaries of $360,000 and $350,000, respectively, for 2017 were appropriate, which were unchanged from their 2016 base salaries.
Bonus.A portion of each executive’s total compensation may be paid as bonus compensation. Our Board takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, our Board takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our executive officers for 2017 has not yet been determined. No bonuses were paid in 2017 for 2016 performance. However, bonuses paid in 2016 for 2015 performance ranged from approximately 45% to 85% of base salary.
Long-Term Incentives. On September 23, 2014, our Board of Directors approved and adopted a long-term compensation plan, the Alta Mesa Holdings, LP Performance Appreciation Rights Plan (the “PARs Plan”), as amended and restated effective September 24, 2014, to provide long-term incentive compensation to key employees and consultants who make significant contributions to us to align our employees with our long-term performance. The PARs Plan is administered by our Board, which determines from time to time which participants will participate in the PARs Plan, the number of PARs to be granted to each participant, the
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stipulated initial designated value (“SIDV”) of each PAR, the designated value of each PAR as of its valuation date, the vesting schedule of each PAR, and any other terms and conditions of the PAR award. Under the PARs Plan, there are special provisions for valuation and payment of a vested PAR award in the event of a Liquidity Event, which is generally defined as follows: an event that (a) satisfies the definition of “change in control” under Section 409A of the Code (“Section 409A”) and (b) is (i) a sale of the all of the assets of High Mesa, (ii) a disposition of all of the equity securities of High Mesa, (iii) an initial public offering of the equity securities of High Mesa or any of its subsidiaries that hold all or substantially all of the assets or (iv) a public offering resulting in gross proceeds of at least $300 million, provided that such event also qualifies as a change in control event under Section 409A. The Business Combination will result in the vesting and payment of all outstanding PARs. We estimate that the value of the PARs that will vest upon the Closing and will be paid by High Mesa will be approximately $10.66 million. In addition, we will not issue any additional PARs following the Business Combination.
A total of 1,000,000 PARs are available for grants to participants under the PARs Plan. The aggregate designated value of all 1,000,000 PARs is approximately equal to 10% of the fair market value of the aggregate interests of all the Class A members in Alta Mesa GP. Absent an intervening Liquidity Event, payment of a PAR award is made on the fixed determination date elected in advance by the recipient of the PAR award, with such fixed determination date occurring no earlier than April 1 of the fifth year following the year of the grant and no later than 10 years from the grant date. All payments made under the PARs Plan in any year are subject to a floating annual cap on the amount of all PAR awards paid under the PARs Plan in a given year (the “Annual Cap”). The Annual Cap is equal to 2.5% multiplied by the fair market value of the aggregate interests of all the Class A members in Alta Mesa GP minus $400 million. If the Annual Cap applies in a year, the amount payable to a PAR award holder on the fixed determination date is hispro-rata amount of the aggregate payments to be made on that date as adjusted for the amount of Annual Cap remaining for that year. Any amounts in excess of the Annual Cap are paid in the next following year, again subject to the Annual Cap.
Upon the occurrence of a payment event, the participant will be entitled to receive a cash amount equal to the increase, if any, between the SIDV of the PAR as of its grant date and the designated value of the PAR as of its payment valuation date. No PARs will be settled in shares; rather, all PAR exercises will be settled solely in cash. Participants will have no rights whatsoever as an equityholder of Alta Mesa GP or of a subsidiary in respect of any PARs.
In 2017 and 2016, the Board awarded 20,000 PARs and 15,000 PARs, respectively, to David Murrell. The SIDV of the 20,000 PARs and 15,000 PARs granted is $40 per unit and vests over a five-year period. In 2016, the Board awarded 60,000 PARs to Michael A. McCabe and 40,000 PARs to Homer “Gene” Cole, respectively. The SIDV of the awards are $40 per unit and vests over a five-year period. Payout of the 2017 and 2016 PARs is based on the increase of the designated value of the PARs over the SIDV of the PARs as determined at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award. In 2015, no PARs were awarded to any of the NEOs.
Benefits.We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis, Chappelle, McCabe, Murrell and Cole with company automobiles. Beginning annually in 2014, we also reimburse each officer, with the exception of Mr. Cole, up to $5,000 annually for tax preparation and planning.
Nonqualified Deferred Compensation.We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated
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employees. The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us. If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years. Participants will receive a distribution of vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service. On January 1, 2017, our Board of Directors made an elective employer contributions to be credited to the accounts of Messrs. Chappelle, Ellis, McCabe, Murrell and Cole in the amounts of $1.6 million, $0.7 million, $0.6 million, $0.3 million and $0.5 million, respectively. Our Board of Directors elected to make this contribution subject to a five-year vesting schedule, with 20% vested each subsequent year, with the exception of Messrs. Murrell and Cole, with none vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting schedule.
Other Compensation. As part of his employment agreement, we provided Mr. McCabe an apartment near our headquarters and paid his commuting expenses to and from his permanent home to Houston, Texas. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas. Such housing and commuting expense prior to his permanent move totaled approximately $30,652 in 2017. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence was outside of the Houston, Texas area. Our Board of Directors considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.
How Elements of Our Compensation Program are Related to Each Other
We view the various components of compensation as related but distinct and emphasizes “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.
Assessment of Risk
Our Board takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.
Accounting and Tax Considerations
Under the PARs Plan, participants are granted PARs with a SIDV. The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a Liquidity Event (as defined in the PARs Plan), but generally can be construed in accordance with the meaning of the term “change in control event” or as a fixed determination date selected by the participant, which is no earlier than within the fifth year from the end of the year containing the grant date. In the case of a Liquidity Event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the PARs Plan) resulting from the Liquidity Event. After any payment valuation date, vested PARs expire regardless of whether or not there is a payment relating thereto. We consider the possibility of payment at a fixed determination date absent the occurrence of a Liquidity Event to be remote as liquidity has not yet occurred. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2017 and 2016. The Business Combination will result in a Liquidity Event as defined under the PARs Plan and will result in payment to the holders of PARs.
Section 162(m) of the Code. Generally, Section 162(m) of the Code disallows a tax deduction to any publicly-held corporation for individual compensation in excess of $1.0 million paid in any taxable year to
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certain of our current or former executive officers. As we were not publicly traded during 2017, our Board of Directors and compensation committee did not take the deductibility limit imposed by Section 162(m) into consideration in setting compensation.
We reserve the right to use our judgment to authorize compensation payments that do not comply with the exemptions in Section 162(m) when we believe that such payments are appropriate and in the best interest of the stockholders, after taking into consideration changing business conditions or the executive’s individual performance and/or changes in specific job duties and responsibilities.
Section 409A of the Code. We have structured our compensation program in a manner intended to comply with Section 409A. If an employee is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such compensation does not comply with Section 409A, then the benefits are generally taxable to the extent they are not subject to a substantial risk of forfeiture. In such case, the employee is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefits includible in income.
All equity awards to our employees, including executive officers, and to our directors will be granted and reflected in our consolidated financial statements, based upon the applicable accounting guidance, at fair market value on the grant date in accordance with FASB ASC, Topic 718, “Compensation—Stock Compensation.”
Stock Ownership Guidelines
Stock ownership guidelines have not been implemented for our named executive officers or directors. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.
Securities Trading Policy
Our securities trading policy provides that executive officers, including the named executive officers, and our directors, may not, among other things, purchase or sell puts or calls to sell or buy our stock, engage in short sales with respect to our stock, buy our securities on margin or otherwise hedge their ownership of our stock. The purchase or sale of stock by our executive officers and directors may only be made during certain windows of time and under the other conditions contained in our policy.
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Summary Compensation
The following table summarizes, with respect to our NEOs, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2017, 2016 and 2015. None of our NEOs participate in a defined benefit pension plan.
All Other | ||||||||||||||||||||||||
Name and Principal Position: | Year | Salary | Bonus(1) | Compensation (7)(8) | Total | |||||||||||||||||||
Harlan H. Chappelle | 2017 | $ | 485,000 | $ | — | $ | 1,614,741 | (2) | $ | 2,099,741 | ||||||||||||||
President, Chief Executive Officer | 2016 | $ | 485,000 | $ | — | $ | 1,423,656 | (2) | $ | 1,908,656 | ||||||||||||||
2015 | $ | 485,000 | $ | — | $ | 42,555 | (2) | $ | 527,555 | |||||||||||||||
Michael E. Ellis | 2017 | $ | 485,000 | $ | — | $ | 733,742 | (3) | $ | 1,218,742 | ||||||||||||||
Chief Operating Officer, Vice President of | 2016 | $ | 485,000 | $ | — | $ | 900,280 | (3) | $ | 1,385,280 | ||||||||||||||
Engineering and Chairman of the Board | 2015 | $ | 485,000 | $ | 300,000 | $ | 20,423 | (3) | $ | 805,423 | ||||||||||||||
Michael A. McCabe | 2017 | $ | 435,000 | $ | — | $ | 718,507 | (4) | $ | 1,153,507 | ||||||||||||||
Vice President, Chief Financial Officer | 2016 | $ | 435,000 | $ | — | $ | 847,348 | (4) | $ | 1,282,348 | ||||||||||||||
2015 | $ | 435,000 | $ | 300,000 | $ | 126,095 | (4) | $ | 861,095 | |||||||||||||||
David Murrell | 2017 | $ | 360,000 | $ | — | $ | 316,904 | (5) | $ | 676,904 | ||||||||||||||
Vice President of Land and Business Development | 2016 | $ | 360,000 | $ | — | $ | 294,163 | (5) | $ | 654,163 | ||||||||||||||
2015 | $ | 360,000 | $ | 175,000 | $ | 14,819 | (5) | $ | 549,819 | |||||||||||||||
Homer “Gene” Cole | 2017 | $ | 350,000 | $ | — | $ | 536,965 | (6) | $ | 886,965 | ||||||||||||||
Vice President, Chief Technical Officer | 2016 | $ | 344,230 | $ | — | $ | 479,949 | (6) | $ | 824,179 | ||||||||||||||
2015 | $ | 300,000 | $ | 250,000 | $ | 21,279 | (6) | $ | 571,279 |
(1) | Bonuses for 2017 have not yet been determined. |
(2) | Mr. Chappelle’s other compensation for the year ended December 31, 2017 consists of $1,581,250 in an elective contribution made by us to his Retirement Plan account, $11,192 in his matching funds to his 401(k) account, $18,825 in auto expenses, and approximately $3,474 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2016 consists of $1,375,000 in an elective contribution made by us to his Retirement Plan account, $11,192 in his matching funds to his 401(k) account, $32,827 in auto expenses, and approximately $4,637 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2015 consists of $8,954 in his matching funds to his 401(k) account, $30,131 in auto expenses, and approximately $3,470 for club membership. |
(3) | Mr. Ellis’ other compensation for the year ended December 31, 2017 consists of $706,250 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $14,242 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2016 consists of $875,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $12,030 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $9,823 in auto expenses. |
(4) | For the year ended December 31, 2017, Mr. McCabe’s other compensation consists of $562,500 in an elective contribution made by us to his Retirement Plan account, $11,042 in matching funds to his 401(k) account, $13,273 in auto expenses and $30,652 in travel and living expenses, which includes $28,384 for an apartment in Houston, Texas and $2,268 for travel, which consists primarily of airfare and the parking. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas. We paid $101,040 for relocation expenses. In 2014, an elective employer contribution was made for the account of Mr. McCabe for $3,000,000 that was fully vested and distributed in 2017. For the year ended December 31, 2016, Mr. McCabe’s other compensation consists of $750,000 in an elective contribution made by us to his Retirement Plan account, $8,270 in matching funds to his 401(k) account, and $89,078 in travel and living expenses, which includes $41,735 for an apartment in Houston, Texas and $47,343 for travel, which |
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consists primarily of airfare and the cost of a leased car and parking. For the year ended December 31, 2015, Mr. McCabe’s other compensation consists of $8,319 in matching funds to his 401(k) account, and $117,776 in travel and living expenses, which includes $41,049 for an apartment in Houston, Texas and $76,727 for travel, which consists primarily of airfare and the cost of rental cars and parking. |
(5) | Mr. Murrell’s other compensation for the year ended December 31, 2017 consists of $300,000 in an elective contribution made by us to his Retirement Plan account, $13,500 in matching funds to his 401(k) account, and $3,404 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2016 consists of $275,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account, and $5,913 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $4,219 in auto expense. |
(6) | Mr. Cole became an executive officer of the Company in 2015. Mr. Cole’s other compensation for the year ended December 31, 2017 consists of $500,000 in an elective contribution made by us to his Retirement Plan account, $13,500 in matching funds to his 401(k) account, $17,724 in auto expense and $5,741 for club membership. Mr. Cole’s other compensation for the year ended December 31, 2016 consists of $450,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $16,699 in auto expense. Mr. Cole’s other compensation for the year ended December 31, 2015 consists of $9,692 in matching funds to his 401(k) account and $10,679 in auto expense. |
(7) | In 2017 and 2016, the Board awarded 20,000 PARs and 15,000 PARs, respectively, to David Murrell. The SIDV of 20,000 PARs and 15,000 PARs granted is $40 per unit and vests over a five-year period. In 2016, the Board awarded 60,000 PARs to Michael A. McCabe and 40,000 PARs to Homer “Gene” Cole, respectively. The SIDV of the awards are $40 per unit and vests over a five-year period. Payout of the 2017 and 2016 PARs is based on the increase of the designated value of the PARs over the SIDV of the PARs as determined at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award. In 2015, no PARs were awarded to any of our NEOs. |
(8) | Amounts provided for all other compensation that are determined based upon reimbursement of expenses to our NEOs are estimates based upon requests for reimbursements submitted prior to the date of this registration statement. |
Narrative Disclosure to Summary Compensation Table
Employment agreements
Mr. Chappelle
Mr. Chappelle entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as President and Chief Executive Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.
Mr. Chappelle’s employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in its sole discretion.
Mr. Ellis
Mr. Ellis entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Operating Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.
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Mr. Ellis’ employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in its sole discretion.
Mr. McCabe
Mr. McCabe entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Financial Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.
Mr. McCabe’s employment agreement provides for a minimum base salary of $435,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in its sole discretion.
Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston, Texas office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas.
Mr. Murrell
Mr. Murrell entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President of Land and Business Development until March 25, 2015, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.
Mr. Murrell’s employment agreement provides for a minimum base salary of $360,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in its sole discretion, subject to a minimum of $50,000.
Outstanding Equity Awards Value at 2017 FiscalYear-End
There were no outstanding equity awards for our NEOs as of December 31, 2017.
Option Exercises and Equity Awards Vested in Fiscal Year 2017
There were no exercises of equity awards and no vesting of equity awards for our NEOs during fiscal 2017.
Pension Benefits
We do not provide pension benefits for our NEOs.
Nonqualified Deferred Compensation
We established the Retirement Plan to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. Our Board of Directors administers the Retirement Plan, and at its sole discretion, designates employees who are eligible to participate. Participants may defer up to 90% of their salary and up to 100% of their cash bonus under the Retirement Plan. Our Board of
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Directors may also, at its sole discretion, make elective employer contributions on behalf of selected participants. The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us. If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years. Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service with us. The Retirement Plan is an unsecured and unfunded promise to pay deferred cash compensation to its participants, who are our general creditors.
The following table shows each NEO’s accumulated benefits under our nonqualified deferred compensation plans for 2017.
NONQUALIFIED DEFERRED COMPENSATION | ||||||||||||||||||||||||||||
Name | Aggregate Balance at December 31, 2016 ($) | Executive Contributions in 2017 ($) | Company Contributions in 2017 ($)(a) | Aggregate Earnings in 2017 ($) | Aggregate Withdrawals / Distributions during 2017 ($) | Aggregate Balance at December 31, 2017 ($)(b) | ||||||||||||||||||||||
Harlan H. Chappelle | $ | 1,375,000 | $ | — | $ | 1,581,250 | (c) | $ | — | $ | — | $ | 2,956,250 | |||||||||||||||
Michael E. Ellis | 875,000 | — | 706,250 | (c) | — | — | 1,581,250 | |||||||||||||||||||||
Michael A. McCabe | 3,750,000 | — | 562,500 | (c) | — | (3,000,000 | ) | 1,312,500 | ||||||||||||||||||||
David Murrell | 600,000 | — | 300,000 | (d) | — | — | 900,000 | |||||||||||||||||||||
Homer “Gene” Cole | 950,000 | — | 500,000 | (d) | — | — | 1,450,000 |
(a) | The amounts shown in this column are also included in “All Other Compensation” column on the Summary Compensation Table. |
(b) | Certain portions shown for each NEO were also reported in the Summary Compensation Table in prior years |
(c) | The contributions are subject to a five-year vesting schedule, with 20% vested each subsequent year. |
(d) | The contributions are subject to a five-year vesting schedule, with zero vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting period. |
In 2017, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any NEO. In 2017, we made elective employer contributions to the accounts for all of our NEOs. Our Board of Directors elected to make the contributions for Harlan H. Chappelle, Michael E. Ellis, and Michael A. McCabe subject to a five-year vesting schedule, with 20% vested each subsequent year. The contributions for David Murrell and Gene Cole were subject to a five-year vesting schedule, with zero vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting period. In 2014, one elective employer contribution was made for the account of Michael A. McCabe. The elective contribution was fully vested and distributed in 2017 in accordance with the terms of the Retirement Plan.
As of fiscal year end 2017, we considered the possibility of payment with respect to outstanding PARs absent the occurrence of a Liquidity Event to be remote. Therefore, no accumulated benefits under the PARs Plan for 2017 has been included. For a description of the PARs Plan, please see the section above entitled “How We Determine Each Element of Compensation—Long-Term Incentives.”
Termination of Employment andChange-in-Control Provisions
Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements that provide them with post-termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntarynot-for-cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2017. In presenting this
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disclosure, we describe amounts earned through December 31, 2017 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, we estimate the amounts which would be paid out to the executives upon their termination.
Provisions under the Employment Agreements
Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures. Additionally, upon termination of employment for any reason, the executive will become 100% fully vested in (1) the unvested portion of any outstanding equity grants held by the executive as of his termination date, and (2) any unvested amounts accrued under any nonqualified deferred compensation or incentive plan or program in which the executive was participating as of his termination date. We expect that the employment agreements will be amended in connection with Closing to remove this accelerated vesting provision.
If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years of the executive’s base salary in effect as of the termination date, or 18 months’ base salary for Mr. Murrell, and two times the annual bonus paid to the executive in the prior year. Assuming termination as of December 31, 2017, for both Messrs. Chappelle and Ellis, the termination benefit would have been $970,000; for Mr. McCabe, $870,000; and for Mr. Murrell, $540,000. In addition, all vested amounts in the executive’s account balance under the Retirement Plan (the “Plan”) would be distributed in accordance with the Plan. Assuming termination as of December 31, 2017, Mr. Chappelle, Mr. Ellis, Mr. McCabe and Mr. Murrell would have received a distribution of $866,250, $491,250, $412,500 and $393,750, respectively. Our executives are each entitled under their employment agreements to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage. For the first 12 months of COBRA coverage, the executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2017, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $12.00 to each. Our total cost of providing this benefit would have been $20,830 for Mr. Chappelle, $30,422 for Mr. Ellis, $9,510 for Mr. McCabe, and $20,830 for Mr. Murrell.
“Cause” means:
• | the executive’s conviction by a court of competent jurisdiction of a crime involving moral turpitude or a felony, or entering the plea of nolo contendere to such crime by the executive; |
• | the commission by the executive of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon us or any affiliate; |
• | the engagement by the executive without approval of the Company and our Board of Directors in any material activity which directly competes with the business of the Company or any affiliate or which would directly result in a material injury to the business or reputation of the Company or any affiliate (including the partners of the Company); or |
• | the breach by the executive of any material provision of the employment agreement, and the executive’s continued failure to cure such breach within a reasonable time period set by us but in no event less than 20 calendar days after the executive’s receipt of such notice. |
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“Good reason” means the occurrence of any of the following, if not cured and corrected by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:
• | the demotion or reduction in title or rank of the executive, or the assignment to the executive of duties that are materially inconsistent with the executive’s current positions, duties, responsibilities and status with us, or any removal of the executive from, or any failure tore-elect the executive to, any of such positions (other than a change due to the executive’s disability or as an accommodation under the Americans with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with (i) the executive’s termination of employment for cause, disability or death, or (ii) the executive’s prior written consent; |
• | the reduction of the executive’s annual base salary or bonus opportunity as effective immediately prior to such reduction without the prior written consent of the executive; or |
• | a relocation of the executive’s principal work location to a location in excess of 50 miles from our then current location. |
“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been an active employee with us for at least five years.
The employment agreements do not separately provide for benefits upon a change of control.
The Retirement Plan generally defines “cause” in the same manner as above for the employment agreements. Under the terms of the Retirement Plan, separation from service for any reason other than cause would result in a distribution event for the participant’s vested account balance. The terms of the Retirement Plan also include provisions whereby each participant’s account balance becomes immediately fully vested if the participant (i) is terminated during the first year after a change in control event for any reason other than cause or (ii) terminates due to death or disability. Normal retirement age is defined under the Retirement Plan as 65 years of age.
Compensation of Directors
The employee andnon-employee members of our Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending board meetings.
Compensation Committee Interlocks and Insider Participation
We do not currently have a compensation committee or an equivalent committee. None of our NEOs has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.
Compensation of Executive Officer and Directors after the Business Combination
After completion of the Business Combination, Mr. James T. Hackett will serve as Chairman of the Board and Chief Operating Officer—Midstream, while Messrs. Harlan H. Chappelle, Michael E. Ellis, Michael A. McCabe, David Murrell, Homer “Gene” Cole and Ronald J. Smith will serve as Chief Executive Officer; Chief Operating Officer—Upstream; Chief Financial Officer, Chief Compliance Officer and Secretary; Vice President of Land and Business Development; Vice President and Chief Technical Officer; and Vice President and Chief Accounting Officer, respectively.
Employment Agreements, Annual Base Salaries and Target Bonuses
On the Closing Date, the Company entered into a letter agreement with Mr. Hackett under which, if the Company terminates Mr. Hackett’s employment without cause or he resigns for good reason, within the meaning
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of and under the letter agreement, he will be entitled to full accelerated vesting of all Company equity awards granted to him during the three years following closing of the Business Combination that are subject to time-based vesting and accelerated vesting of any such Company equity awards that are subject to performance-based vesting at the target level of performance. The Board also approved an annual base salary for Mr. Hackett of $450,000, effective on the Closing Date, and a target annual bonus amount under an annual performance bonus program for 2018 of 95% of his annual base salary.
In addition, on the Closing Date, the Company entered into new employment agreements with each of Messrs. Chappelle, Ellis, McCabe, Cole, Murrell and Smith. The employment agreements supersede each executive’s previous employment agreement with Alta Mesa and are for terms of three years (or two years for Mr. Smith).
Mr. Chappelle’s employment agreement entitles him to receive an annual base salary of $830,000 and to participate in an annual performance bonus program with a target bonus award determined by the Board. For 2018, Mr. Chappelle’s target annual bonus amount under this program will be 125% of his annual base salary. Mr. Chappelle is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If the Company terminates Mr. Chappelle’s employment without cause or he resigns for good reason, within the meaning of and under his employment agreement, Mr. Chappelle will be entitled to receive (i) a prorated annual bonus for the year of termination, determined based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all Company equity awards that are subject to time-based vesting, accelerated vesting of any Company equity awards that are subject to performance-based vesting at the target level of performance and full accelerated vesting of any nonqualified deferred compensation account balance or benefit, (iii) alump-sum payment equal to the sum of $40,000 for outplacement services, two years of his annual base salary and two times the greater of his target annual bonus and the annual bonus paid to him for the prior year and (iv) payment for up to 18 months of his premiums for continued coverage in the Company’s group health plans and, thereafter, continued participation in the Company’s group health plans at his cost for up to an additional 18 months. Mr. Chappelle is also entitled to receive the amounts under clauses (i), (iii) and (iv) of the preceding sentence if his employment terminates due to his death or disability, under and within the meaning of his employment agreement. If Mr. Chappelle’s qualifying employment termination occurs during thetwenty-one months following a change in control (within the meaning of the employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, Mr. Chappelle will be entitled to an additionallump-sum payment equal to the sum of one year of his annual base salary and one times the greater of his target annual bonus and the annual bonus paid to him for the prior year. Mr. Chappelle’s right to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, is conditioned upon his executing a general release of claims in our favor. Mr. Chappelle has also agreed to refrain from competing with the Company or soliciting its customers or employees during and for a period of 12 months following his employment with the Company.
The employment agreements for Messrs. Ellis, McCabe, Cole, Murrell and Smith entitle them to receive annual base salaries of $520,000, $450,000, $450,000, $360,000, and $270,000, respectively, and to participate in an annual performance bonus program with a target bonus award determined by the Board. For 2018, Mr. Ellis’s, Mr. McCabe’s and Mr. Cole’s target annual bonus amounts under this program will be 95% of their respective annual base salaries, and Mr. Murrell’s and Mr. Smith’s target annual bonus amounts under this program will be 65% of their respective annual base salaries. Each of Messrs. Ellis, McCabe, Cole, Murrell and Smith is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If the Company terminates Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s or Mr. Smith’s employment without cause or he resigns for good reason, within the meaning of and under his employment agreement, he will be entitled to receive (i) a prorated annual bonus for the year of termination, determined based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all Company equity awards that are subject to time-based vesting, accelerated vesting of any Company equity awards that are
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subject to performance-based vesting at the target level of performance and full accelerated vesting of any nonqualified deferred compensation account balance or benefit, (iii) alump-sum payment equal to the sum of $24,000 (or $20,000 for Mr. Smith) for outplacement services, 18 months (or 12 months for Mr. Smith) of his annual base salary and 1.5 times (or one times for Mr. Smith) the greater of his target annual bonus and the annual bonus paid to him for the prior year and (iv) payment for up to 18 months of his premiums for continued coverage in the Company’s group health plans and, thereafter, for Messrs. Ellis, McCabe, Cole and Murrell, continued participation in the Company’s group health plans at his cost for up to an additional 6 months. Messrs. Ellis, McCabe, Cole, Murrell and Smith would each also be entitled to receive the amounts under clauses (i), (iii) and (iv) of the preceding sentence if his employment terminates due to death or disability, under and within the meaning of his employment agreement. If Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s or Mr. Smith’s qualifying termination of employment occurs during the fifteen months following a change in control (within the meaning of his employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, he will be entitled to an additionallump-sum payment equal to the sum of six months of his annual base salary and 0.5 times the greater of his target annual bonus and the annual bonus paid to him for the prior year. Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s and Mr. Smith’s rights to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, are conditioned upon executing a general release of claims in our favor. Each of Messrs. Ellis, McCabe, Cole, Murrell and Smith has also agreed to refrain from competing with the Company or soliciting its customers or employees during and for a period of 12 months following his employment with the Company.
The employment agreements for Messrs. Chappelle, Ellis, McCabe, Cole, Murrell and Smith further entitle them, if a termination of employment occurs during the three years (or two years for Mr. Smith) following the Closing Date, to payment for any excise taxes imposed under Section 4999 of the Internal Revenue Code as a result of a change in control (within the meaning of their respective employment agreements) other than the Business Combination plus an additional amount that puts the executive in the sameafter-tax position he would have been absent the imposition of excise taxes under Section 4999 of the Internal Revenue Code.
LTIP Awards
On February 6, 2018, the stockholders of the Company approved the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”), effective upon the closing of the Business Combination.
The Company issued the following awards of options to purchase shares of Class A Common Stock under the LTIP and approved, effective upon the effectiveness of a registration statement on FormS-8 filed by the Company with the SEC covering the offer and sale of securities under the LTIP and subject to the executive’s continued employment until such time, the following awards of restricted shares of Class A Common Stock to Messrs. Hackett, Chappelle, Ellis, McCabe, Cole and Murrell under the LTIP:
Name | Stock Options (#) | Restricted Stock (#) | ||
James T. Hackett | 589,623 | — | ||
Harlan H. Chappelle | 589,623 | — | ||
Michael E. Ellis | 353,774 | — | ||
Michael A. McCabe | 283,019 | 125,786 | ||
Homer “Gene” Cole | 283,019 | 125,785 | ||
David Murrell | 106,132 | 47,170 | ||
Ronald J. Smith | 53,066 | 23,585 |
The stock options were issued with exercise prices equal to the initial sale price on the Closing Date for Class A Common Stock on the NASDAQ, and the Compensation Committee amended the definition of fair
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market value in the LTIP to mean such initial sale price for purposes of these grants. The stock options and restricted stock awards will each vest in three substantially equal annual installments on the first three anniversaries of the Closing Date, subject to the executive’s continued service with us and the accelerated vesting terms of the agreements with the relevant executive described above.
Director Compensation
Effective as of the Closing, the Company adopted a director compensation program under which each director who is not an employee of the Company or a subsidiary and is not affiliated with Riverstone, Bayou City, HPS or AM Management will receive the following cash amounts for their services on our Board:
• | An annual director fee of $75,000; |
• | If the director serves on a committee of our Board, an additional annual fee as follows: |
• | Chairperson of the Audit Committee—$22,500; |
• | Audit Committee member other than the chairperson—$10,000; |
• | Chairperson of the Compensation Committee—$15,000; |
• | Compensation Committee member other than the chairperson—$6,000; |
• | Chairperson of the Nominating and Corporate Governance Committee—$12,500; and |
• | Nominating and Corporate Governance Committee member other than the chairperson—$5,000. |
• | If the director serves on a committee of our Board, an additional per meeting fee of $1,500 for: |
• | Each member of the Audit Committee for each Audit Committee meeting attended per calendar year in excess of eight meetings; |
• | Each member of the Compensation Committee for each Compensation Committee meeting attended per calendar year in excess of six meetings; and |
• | Each member of the Nominating and Corporate Governance Committee for each Nominating and Corporate Governance Committee meeting attended per calendar year in excess of six meetings. |
Director fees under the program will be payable in arrears in four equal quarterly installments not later than the 15th day following the final day of each fiscal quarter, provided that the amount of each payment in respect of annual fees will be prorated for any portion of a quarter that a director is not serving on our Board or on a particular committee, and no fee will be payable in respect of any period prior to the Closing.
The Company has also approved an award of 18,344 fully vested shares of Class A Common Stock to each of Ms. Diana J. Walters and Messrs. William D. Gutermuth, Jeffrey H. Tepper and Donald R. Sinclair under the LTIP, effective upon the effectiveness of a registration statement on FormS-8 filed by the Company with the SEC covering the offer and sale of securities under the LTIP and subject to the director’s continued service until such time.
The LTIP
Our Board approved the LTIP on January 12, 2018 and on February 6, 2018, our stockholders approved the adoption of the LTIP. A total of 50,000,000 shares of Class A Common Stock will be reserved for issuance under the LTIP. The purpose of the LTIP is to enhance our ability to attract, retain and motivate persons who make (or are expected to make) important contributions to us by providing these individuals with equity ownership opportunities. We believe that the LTIP is essential to our success. Equity awards are intended to motivate high levels of performance and align the interests of our directors, employees and consultants with those of our stockholders by giving directors,
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employees and consultants the perspective of an owner with an equity stake in us and providing a means of recognizing their contributions to our success. Our Board and management believe that equity awards are necessary to remain competitive in our industry and are essential to recruiting and retaining the highly qualified individuals who help us meet our goals.
Background for Determining the Share Reserve Under the LTIP
In its determination to adopt and approve the LTIP, our Board reviewed an analysis prepared by FW Cook, its independent compensation consultant, which included an analysis of market data and trends and our anticipated equity usage. Specifically, the Board considered FW Cook’s review of the size of long-term incentive plan pools reserved by companies in the exploration & production industry at the time of their initial public offerings, as well as the aggregate equity usage practices for other companies in this industry. If the LTIP is approved, we estimate that the shares reserved for issuance under the LTIP would be sufficient for approximately four to six years of awards, noting that the share reserve under the LTIP could last for a longer or shorter period of time dependent upon, among other things, the competitiveness of ongoing grants, any changes in stock price and on our future equity grant practices, which we cannot predict with any degree of certainty at this time.
Summary of the LTIP
This section summarizes certain principal features of the LTIP. The summary is qualified in its entirety by reference to the complete text of the LTIP, which is filed as an exhibit to the Registration Statement of which this prospectus is a part.
Eligibility and Administration
Our employees, consultants and directors, and employees and consultants of our subsidiaries, will be eligible to receive awards under the LTIP. We and our subsidiaries expect to have approximately 269 employees who will be eligible to receive awards under the LTIP, in addition to its independent directors and Chairman of the Board.
The LTIP will be administered by our Board, which may delegate its duties and responsibilities to one or more committees of our directors and/or officers (referred to collectively as the plan administrator), subject to the limitations imposed under the LTIP, Section 16 of the Exchange Act, stock exchange rules and other applicable laws. The plan administrator will have the authority to take all actions and make all determinations under the LTIP, to interpret the LTIP and award agreements and to adopt, amend and repeal rules for the administration of the LTIP as it deems advisable. The plan administrator will also have the authority to determine which eligible service providers receive awards, grant awards and set the terms and conditions of all awards under the LTIP, including any vesting and vesting acceleration provisions, subject to the conditions and limitations in the LTIP.
Shares Available for Awards
An aggregate of 50,000,000 shares of Class A Common Stock will be available for issuance under the LTIP, all of which may be issued upon the exercise of incentive stock options. Shares issued under the LTIP may be authorized but unissued shares, shares purchased on the open market or treasury shares.
If an award under the LTIP expires, lapses or is terminated, exchanged for cash, surrendered, repurchased, canceled without having been fully exercised or forfeited, any unused shares subject to the award will again be available for new grants under the LTIP. However, the LTIP does not allow the shares available for grant under the LTIP to be recharged or replenished with shares that:
• | are tendered or withheld to satisfy the exercise price of an option; |
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• | are tendered or withheld to satisfy tax withholding obligations for any award; |
• | are subject to a stock appreciation right but are not issued in connection with the stock settlement of the stock appreciation right; or |
• | are purchased on the open market with cash proceeds from the exercise of options. |
Awards granted under the LTIP in substitution for any options or other stock or stock-based awards granted by an entity before the entity’s merger or consolidation with us (or any of our subsidiaries) or our (or any of our subsidiary’s) acquisition of the entity’s property or stock will not reduce the shares available for grant under the LTIP, but will count against the maximum number of shares that may be issued upon the exercise of incentive stock options.
Awards
The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”) and nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock or cash based awards. Certain awards under the LTIP may constitute or provide for payment of “nonqualified deferred compensation” under Section 409A of the Code. All awards under the LTIP will be set forth in award agreements, which will detail the terms and conditions of awards, including any applicable vesting and payment terms and post-termination exercise limitations. A brief description of each award type follows.
• | Stock Options and SARs.Stock options provide for the purchase of shares of Class A Common Stock in the future at an exercise price set on the grant date. ISOs, in contrast to NSOs, may provide tax deferral beyond exercise and favorable capital gains tax treatment to their holders if certain holding period and other requirements of the Code are satisfied. SARs entitle their holder, upon exercise, to receive from us an amount equal to the appreciation of the shares subject to the award between the grant date and the exercise date. The plan administrator will determine the number of shares covered by each option and SAR, the exercise price of each option and SAR and the conditions and limitations applicable to the exercise of each option and SAR. The exercise price of a stock option or SAR will not be less than 100% of the fair market value of the underlying share on the grant date (or 110% in the case of ISOs granted to certain significant stockholders), except with respect to certain substitute awards granted in connection with a corporate transaction. The term of a stock option or SAR may not be longer than 10 years (or five years in the case of ISOs granted to certain significant stockholders). |
• | Restricted Stock.Restricted stock is an award of nontransferable shares of Class A Common Stock that remain forfeitable unless and until specified conditions are met and which may be subject to a purchase price. Upon issuance of restricted stock, recipients generally have the rights of a stockholder with respect to such shares, which generally include voting rights in such shares and the right to receive dividends and other distributions in relation to the award; however, dividends may be paid with respect to restricted stock only to the extent the vesting conditions have been satisfied and the restricted stock vests. The terms and conditions applicable to restricted stock will be determined by the plan administrator, subject to the conditions and limitations contained in the LTIP. |
• | RSUs.RSUs are contractual promises to deliver shares of Class A Common Stock in the future, which may also remain forfeitable unless and until specified conditions are met and may be accompanied by the right to receive the equivalent value of dividends paid on shares of Class A Common Stock prior to the delivery of the underlying shares (i.e., dividend equivalent rights); however, dividend equivalents with respect to an award that are based on dividends paid prior to the vesting of such award will only be paid out to the holder to the extent that the vesting conditions are subsequently satisfied and the award vests. The plan administrator may provide that the delivery of the shares underlying RSUs will be deferred on a mandatory basis or at the election of the participant. The terms and conditions applicable to RSUs will be determined by the plan administrator, subject to the conditions and limitations contained in the LTIP. |
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• | Other Stock or Cash Based Awards.Other stock or cash based awards are awards of cash, fully vested shares of Class A Common Stock and other awards valued wholly or partially by referring to, or otherwise based on, shares of Class A Common Stock or other property. Other stock or cash based awards may be granted to participants and may also be available as a payment form in the settlement of other awards, as standalone payments and as payment in lieu of compensation to which a participant is otherwise entitled. The plan administrator will determine the terms and conditions of other stock or cash based awards, which may include any purchase price, performance goal, transfer restrictions, vesting conditions and payment terms. |
Performance-Based Awards
The plan administrator may select performance criteria for an award to establish performance goals for a performance period. Performance criteria under the LTIP may include, but are not limited to, the following: net earnings or losses (either before or after one or more of interest, taxes, depreciation, amortization, andnon-cash equity-based compensation expense); gross or net sales or revenue or sales or revenue growth; net income (either before or after taxes) or adjusted net income; profits (including but not limited to gross profits, net profits, profit growth, net operation profit or economic profit), profit return ratios or operating margin; budget or operating earnings (either before or after taxes or before or after allocation of corporate overhead and bonus); cash flow (including operating cash flow and free cash flow or cash flow return on capital); return on assets; return on capital or invested capital; cost of capital; return on stockholders’ equity; total stockholder return; return on sales; costs, reductions in costs and cost control measures; expenses; working capital; earnings or loss per share; adjusted earnings or loss per share; price per share or dividends per share (or appreciation in or maintenance of such price or dividends); regulatory achievements or compliance; implementation, completion or attainment of objectives relating to research, development, regulatory, commercial, or strategic milestones or developments; market share; economic value or economic value added models; division, group or corporate financial goals; individual business objectives; production or growth in production; reserves or added reserves; growth in reserves per share; inventory growth; environmental, health and/or safety performance; effectivenessof hedging programs; improvements in internal controls and policies and procedures; customer satisfaction/growth; customer service; employee satisfaction; recruitment and maintenance of personnel; human resources management; supervision of litigation and other legal matters; strategic partnerships and transactions; financial ratios (including those measuring liquidity, activity, profitability or leverage); debt levels or reductions; sales-related goals; financing and other capital raising transactions; cash on hand; acquisition activity; investment sourcing activity; drilling results; proved reserves, reserve replacement, drillbit reserve replacement or reserve growth; exploration and development costs, capital expenditures, finding and development costs, drillbit finding and development costs, operating costs (including, but not limited to, lease operating expenses, severance taxes and other production taxes, gathering and transportation costs and other components of operating expenses), based operating costs or production costs; production volumes, production growth, or debt-adjusted production growth, which may be of oil, gas, natural gas liquids or any combination thereof; and marketing initiatives, any of which may be measured in absolute terms or as compared to any incremental increase or decrease. Such performance goals also may be based solely by reference to the company’s performance or the performance of a subsidiary, division, business segment or business unit of the company or a subsidiary, or based upon performance relative to performance of other companies or upon comparisons of any of the indicators of performance relative to performance of other companies. When determining performance goals, the plan administrator may provide for exclusion of the impact of an event or occurrence which the plan administrator determines should appropriately be excluded, including, without limitation,non-recurring charges or events, acquisitions or divestitures, changes in the corporate or capital structure, events unrelated to the business or outside of the control of management, foreign exchange considerations, and legal, regulatory, tax or accounting changes.
Prohibition on Repricing
Under the LTIP, the plan administrator may not, except in connection with equity restructurings and certain other corporate transactions as described below, without the approval of our stockholders, authorize the repricing
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of any outstanding option or SAR to reduce its price per share, or cancel any option or SAR in exchange for cash or another award when the price per share exceeds the Fair Market Value (as that term is defined in the LTIP) of the underlying shares.
Certain Transactions
In connection with certain corporate transactions and events affecting our Class A Common Stock, including a change in control, or change in any applicable laws or accounting principles, the plan administrator has broad discretion to take action under the LTIP to prevent the dilution or enlargement of intended benefits, facilitate the transaction or event or give effect to the change in applicable laws or accounting principles. This includes canceling awards for cash or property, accelerating the vesting of awards, providing for the assumption or substitution of awards by a successor entity, adjusting the number and type of shares subject to outstanding awards and/or with respect to which awards may be granted under the LTIP and replacing awards under the LTIP. In addition, in the event of certainnon-reciprocal transactions with our stockholders, the plan administrator will make equitable adjustments to the LTIP and outstanding awards as it deems appropriate to reflect the transaction.
Provisions of the LTIP Relating to Director Compensation
The LTIP provides that the plan administrator may establish compensation fornon-employee directors from time to time subject to the LTIP’s limitations. The plan administrator will from time to time determine the terms, conditions and amounts of allnon-employee director compensation in its discretion and pursuant to the exercise of its business judgment, taking into account such factors, circumstances and considerations as it shall deem relevant from time to time, provided that the sum of any cash compensation or other compensation and the grant date fair value of any equity awards granted under the LTIP as compensation for services as anon-employee director during any fiscal year may not exceed $500,000. The plan administrator may make exceptions to this limit for individualnon-employee directors in extraordinary circumstances, as the plan administrator may determine in its discretion, subject to the limitations in the LTIP.
Plan Amendment and Termination
Our board of directors may amend or terminate the LTIP at any time; however, no amendment, other than an amendment that increases the number of shares available under the LTIP, may materially and adversely affect an award outstanding under the LTIP without the consent of the affected participant and stockholder approval will be obtained for any amendment to the extent necessary to comply with applicable laws. The LTIP will remain in effect until the tenth anniversary of the earlier of (i) the date our board of directors adopted the LTIP and (ii) the date our stockholders approve the LTIP, unless earlier terminated by our board of directors. No awards may be granted under the LTIP after its termination.
Foreign Participants, Claw-back Provisions, Transferability and Participant Payments
The plan administrator may modify awards granted to participants who are foreign nationals or employed outside the United States or establish subplans or procedures to address differences in laws, rules, regulations or customs of such foreign jurisdictions. All awards will be subject to any company claw-back policy as set forth in such claw-back policy or the applicable award agreement. Except as the plan administrator may determine or provide in an award agreement, awards under the LTIP are generallynon-transferrable, except by will or the laws of descent and distribution, or, subject to the plan administrator’s consent, pursuant to a domestic relations order, and are generally exercisable only by the participant. With regard to tax withholding obligations arising in connection with awards under the LTIP, and exercise price obligations arising in connection with the exercise of stock options under the LTIP, the plan administrator may, in its discretion, accept cash, wire transfer or check, shares of Class A Common Stock that meet specified conditions, a promissory note, a “market sell order,” such other consideration as the plan administrator deems suitable or any combination of the foregoing.
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Material U.S. Federal Income Tax Consequences
The following summary is based on an analysis of the Code as currently in effect, existing laws, judicial decisions, administrative rulings, regulations and proposed regulations, all of which are subject to change. Moreover, the following is only a summary of United States federal income tax consequences. Actual tax consequences to participants may be either more or less favorable than those described below depending on the participant’s particular circumstances.
ISO. No income will be recognized by a participant for federal income tax purposes upon the grant or exercise of an ISO. The basis of shares transferred to a participant upon exercise of an ISO is the price paid for the shares. If the participant holds the shares for at least one year after the transfer of the shares to the participant and two years after the grant of the option, the participant will recognize capital gain or loss upon sale of the shares received upon exercise equal to the difference between the amount realized on the sale and the basis of the stock. Generally, if the shares are not held for that period, the participant will recognize ordinary income upon disposition in an amount equal to the excess of the fair market value of the shares on the date of exercise over the amount paid for the shares, or if less, the gain on disposition. Any additional gain realized by the participant upon the disposition will be a capital gain. The excess of the fair market value of shares received upon the exercise of an ISO over the option price for the shares is generally an item of adjustment for the participant for purposes of the alternative minimum tax. Therefore, although no income is recognized upon exercise of an ISO, a participant may be subject to alternative minimum tax as a result of the exercise.
NSOs. No income is expected to be recognized by a participant for federal income tax purposes upon the grant of an NSO. Upon exercise of an NSO, the participant will recognize ordinary income in an amount equal to the excess of the fair market value of the shares on the date of exercise over the amount paid for the shares. Income recognized upon the exercise of an NSO will be considered compensation subject to withholding at the time the income is recognized, and, therefore, the participant’s employer must make the necessary arrangements with the participant to ensure that the amount of the tax required to be withheld is available for payment. NSOs are designed to provide the employer with a deduction equal to the amount of ordinary income recognized by the participant at the time of the recognition by the participant, subject to the deduction limitations described below.
SARs. There is expected to be no federal income tax consequences to either the participant or the employer upon the grant of SARs. Generally, the participant will recognize ordinary income subject to withholding upon the receipt of payment pursuant to SARs in an amount equal to the aggregate amount of cash and the fair market value of any common stock received. Subject to the deduction limitations described below, the employer generally will be entitled to a corresponding tax deduction equal to the amount includible in the participant’s income.
Restricted Stock. If the restrictions on an award of shares of restricted stock are of a nature that the shares are both subject to a substantial risk of forfeiture and are not freely transferable (within the meaning of Section 83 of the Code), the participant will not recognize income for federal income tax purposes at the time of the award unless the participant affirmatively elects to include the fair market value of the shares of restricted stock on the date of the award, less any amount paid for the shares, in gross income for the year of the award pursuant to Section 83(b) of the Code. In the absence of this election, the participant will be required to include in income for federal income tax purposes on the date the shares either become freely transferable or are no longer subject to a substantial risk of forfeiture (within the meaning of Section 83 of the Code), the fair market value of the shares of restricted stock on such date, less any amount paid for the shares. The employer will be entitled to a deduction at the time of income recognition to the participant in an amount equal to the amount the participant is required to include in income with respect to the shares, subject to the deduction limitations described below. If a Section 83(b) election is made within 30 days after the date the restricted stock is received, the participant will recognize ordinary income at the time of the receipt of the restricted stock, and the employer will be entitled to a corresponding deduction, equal to the fair market value of the shares at the time, less the amount paid, if any, by the participant for the restricted stock. If a Section 83(b) election is made, no additional
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income will be recognized by the participant upon the lapse of restrictions on the restricted stock, but, if the restricted stock is subsequently forfeited, the participant may not deduct the income that was recognized pursuant to the Section 83(b) election at the time of the receipt of the restricted stock. No participant may make a Section 83(b) election with respect to any award granted under the LTIP without the consent of the plan administrator.
Any dividends paid to a participant holding restricted stock before the expiration of the restriction period will be additional compensation taxable as ordinary income to the participant subject to withholding, unless the participant made an election under Section 83(b). Subject to the deduction limitations described below, the employer generally will be entitled to a corresponding tax deduction equal to the dividends includible in the participant’s income as compensation. If the participant has made a Section 83(b) election, the dividends will be dividend income, rather than additional compensation, to the participant.
If the restrictions on an award of restricted stock are not of a nature that the shares are both subject to a substantial risk of forfeiture and not freely transferable, within the meaning of Section 83 of the Code, the participant will recognize ordinary income for federal income tax purposes at the time of the transfer of the shares in an amount equal to the fair market value of the shares of restricted stock on the date of the transfer, less any amount paid therefore. The employer will be entitled to a deduction at that time in an amount equal to the amount the participant is required to include in income with respect to the shares, subject to the deduction limitations described below.
RSUs. There will be no federal income tax consequences to either the participant or the employer upon the grant of RSUs. Generally, the participant will recognize ordinary income subject to withholding upon the receipt of cash and/or transfer of shares of common stock in payment of the RSUs in an amount equal to the aggregate of the cash received and the fair market value of the common stock so transferred. Subject to the deduction limitations described below, the employer generally will be entitled to a corresponding tax deduction equal to the amount includible in the participant’s income.
Generally, a participant will recognize ordinary income subject to withholding upon the payment of any dividend equivalents paid with respect to an award in an amount equal to the cash the participant receives. Subject to the deduction limitations described below, the employer generally will be entitled to a corresponding tax deduction equal to the amount includible in the participant’s income.
Limitations on the Employer’s Compensation Deduction. Section 162(m) of the Code limits the deduction certain employers may take for otherwise deductible compensation payable to certain current or former executive officers of the employer to the extent the compensation paid to such an officer for the year exceeds $1 million.
Excess Parachute Payments. Section 280G of the Code limits the deduction that the employer may take for otherwise deductible compensation payable to certain individuals if the compensation constitutes an “excess parachute payment.” Excess parachute payments arise from payments made to disqualified individuals that are in the nature of compensation and are contingent on changes in ownership or control of the employer or certain affiliates. Accelerated vesting or payment of outstanding awards under the LTIP upon a change in ownership or control of the employer or its affiliates could result in excess parachute payments. In addition to the deduction limitation applicable to the employer, a disqualified individual receiving an excess parachute payment is subject to a 20% excise tax on the amount thereof.
Application of Section 409A of the Code. Section 409A of the Code imposes an additional 20% tax and interest on an individual receivingnon-qualified deferred compensation under a plan that fails to satisfy certain requirements. For purposes of Section 409A,“non-qualified deferred compensation” includes equity-based incentive programs, including some stock options, SARs and RSU awards. Generally speaking, Section 409A does not apply to ISOs,non-discounted NSOs and SARs if no deferral is provided beyond exercise, or restricted stock.
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The awards made pursuant to the LTIP are expected to be designed in a manner intended to comply with the requirements of Section 409A of the Code to the extent the awards granted under the LTIP are not exempt from Section 409A. However, if the LTIP fails to comply with Section 409A in operation, a participant could be subject to the additional taxes and interest.
State and local tax consequences may in some cases differ from the federal tax consequences. The foregoing summary of the income tax consequences in respect of the LTIP is for general information only. Interested parties should consult their own advisors as to specific tax consequences of their awards.
The LTIP is not subject to the Employee Retirement Income Security Act of 1974, as amended, and is not intended to be qualified under Section 401(a) of the Code.
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Founder Shares
On November 21, 2016, our Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from us, for an aggregate purchase price of $25,000, or approximately $0.002 per share. On March 2017, we effected a stock dividend of 14,375,000 shares of Class B Common Stock, resulting in our Sponsor holding an aggregate of 25,875,000 founder shares. In March 2017, our Sponsor transferred 33,000 founder shares to each of our then independent directors (together with our Sponsor, the “initial stockholders”) at their original purchase price. On February 9, 2018, all of the outstanding founder shares were automatically converted into shares of Class A Common Stock on aone-for-one basis in connection with the Closing.
The initial stockholders have agreed, subject to limited exceptions, not to transfer, assign or sell any of their shares of Class A Common Stock received upon conversion of their founder shares until the earlier to occur of: (A) one year after the completion of the Business Combination or (B) subsequent to the Business Combination, (x) if the last sale price of the Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30 trading day period commencing at least 150 days after the Business Combination, or (y) the date on which we complete a liquidation, merger, stock exchange or other similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property.
Private Placement Warrants
On March 29, 2017, our Sponsor purchased from us 15,133,333 Private Placement Warrants at a price of $1.50 per whole warrant ($22,700,000 in the aggregate) in a private placement that occurred simultaneously with the closing of our IPO. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was placed in our trust account along with the proceeds from our IPO. The Private Placement Warrants arenon-redeemable and exercisable on a cashless basis so long as they are held by our Sponsor or its permitted transferees.
Our Sponsor has agreed, subject to limited exceptions, not to transfer, assign or sell any of the Private Placement Warrants until 30 days after the completion of the Business Combination.
Forward Purchase Agreement
In March 2017, we entered the Forward Purchase Agreement pursuant to which Fund VI Holdings agreed to purchase an aggregate of up to 40,000,000 shares of our Class A Common Stock, plus an aggregate of up to 13,333,333 warrants (“Forward Purchase Warrant”), for an aggregate purchase price of up to $400,000,000 or $10.00 per unit (collectively, “Forward Purchase Units”). Each Forward Purchase Warrant has the same terms as each of the Private Placement Warrants.
On February 9, 2018, the Fund VI Holdings purchased 40,000,000 units pursuant to the Forward Purchase Agreement for an aggregate purchase price of $400 million.
Related Party Loans
On November 22, 2016, the Sponsor agreed to loan us an aggregate of up to $300,000 to cover expenses related to the IPO pursuant to a promissory note (the “2016 Note”). This loan isnon-interest bearing and was payable on the earlier of March 31, 2017 or the completion of the IPO. On November 22, 2016, we borrowed $300,000 under the 2016 Note. On March 29, 2017, the full $300,000 balance of the 2016 Note was repaid to the Sponsor.
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On September 27, 2017, the Sponsor agreed to loan us an aggregate of up to $2,000,000 to cover expenses related to the Business Combination pursuant to a promissory note (the “2017 Note”). This loan wasnon-interest bearing and payable on the earlier of March 29, 2019 or the date on which we consummate a business combination. On September 27, 2017, we borrowed $2,000,000 under the 2017 Note. On February 9, 2018, the full $2,000,000 balance of the 2017 Note was repaid to the Sponsor.
Indemnity Agreements
On the Closing Date, we entered into indemnity agreements with Messrs. David M. Leuschen, Pierre F. Lapeyre, Jr., William W. McMullen, Don Dimitrievich and Donald R. Sinclair, each of whom became a director following the Business Combination, and Messrs. Harlan H. Chappelle, Michael E. Ellis, Michael A. McCabe, David Murrell, Homer “Gene” Cole and Ronald J. Smith, each of who became executive officers and/or directors of the Company following the Business Combination. In addition, we amended the indemnity agreements previously entered into with Messrs. Jim T. Hackett, William D. Gutermuth and Jeffrey H. Tepper and Ms. Diana J. Walters to make certain changes to reflect the Closing. Each indemnity agreement provides that, subject to limited exceptions, and among other things, we will indemnify the director or executive officer to the fullest extent permitted by law for claims arising in his or her capacity as our director or officer.
Administrative Support Agreement
On March 24, 2017, we entered into an administrative support agreement pursuant to which we agreed to pay an affiliate of our Sponsor a total of $10,000 per month for office space, utilities and secretarial and administrative support. We paid the affiliate of our Sponsor $30,000 and $60,000 for such services for the three and nine months ended September 30, 2017, respectively. Following the Closing, we no longer pay these monthly fees.
Amended and Restated Limited Partnership Agreement of SRII Opco
In connection with the Closing of the Business Combination, we and the Contributors entered into SRII Opco’s amended and restated agreement limited partnership agreement (the “A&R LP Agreement”). The operations of SRII Opco, and the rights and obligations of the holders of SRII Opco Common Units, are set forth in the A&R LP Agreement.
Appointment as General Partner.We are the sole member of and have ownership and voting control over SRII Opco GP, LLC, a Delaware limited liability company and sole general partner of SRII Opco (the “General Partner”). The General Partner is able to control all of theday-to-day business affairs and decision-making of SRII Opco without the approval of any other partner, unless otherwise stated in the A&R LP Agreement. As such, the General Partner, through its officers and directors, is responsible for all operational and administrative decisions of SRII Opco and theday-to-day management of SRII Opco’s business. Pursuant to the terms of the A&R LP Agreement, the General Partner cannot, under any circumstances, be removed as the sole general partner of SRII Opco except by its election. The board of managers of the General Partner will have the same members as our Board and the officers of the General Partner will be the same as our officers.
Compensation. The General Partner is not entitled to compensation for its services as general partner. The General Partner is entitled to reimbursement by SRII Opco for any reasonableout-of-pocket expenses incurred on behalf of SRII Opco, including all of our fees, expenses and costs of being a public company (including public reporting obligations, proxy statements, stockholder meetings, stock exchange fees, transfer agent fees, SEC and FINRA filing fees and offering expenses) and maintaining our corporate existence.
Distributions. The A&R LP Agreement allows for distributions to be made by SRII Opco to its partners on a pro rata basis out of “distributable cash” (as defined in the A&R LP Agreement). We expect SRII Opco may make distributions out of distributable cash periodically to the extent permitted by the debt agreements of SRII Opco and necessary to enable us to cover our operating expenses and other obligations, as well as to make
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dividend payments, if any, to the holders of our Class A Common Stock. In addition, the A&R LP Agreement generally requires SRII Opco to make pro rata distributions to its partners, including us, in an amount at least sufficient to allow us to pay our taxes.
SRII Opco Common Unit Redemption Right. The A&R LP Agreement provides a redemption right to the Contributors which entitles them to cause SRII Opco to redeem, from time to time, all or a portion of their SRII Opco Common Units for, at SRII Opco’s option, newly-issued shares of our Class A Common Stock on aone-for-one basis or a cash payment equal to the average of the volume-weighted closing price of one share of Class A Common Stock for the five trading days prior to the date the Contributors deliver a notice of redemption for each SRII Opco Common Unit redeemed (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). In the event of a “reclassification event” (as defined in the A&R LP Agreement), the General Partner is to ensure that each SRII Opco Common Unit is redeemable for the same amount and type of property, securities or cash that a share of Class A Common Stock becomes exchangeable for or converted into as a result of such “reclassification event.” Upon the exercise of the redemption right, the Contributors will surrender their SRII Opco Common Units to SRII Opco for cancellation. The A&R LP Agreement requires that we contribute cash or shares of our Class A Common Stock to SRII Opco in exchange for a number of SRII Opco Common Units in SRII Opco equal to the number of SRII Opco Common Units to be redeemed from the Contributor. SRII Opco will then distribute such cash or shares of our Class A Common Stock to such Contributor to complete the redemption. Upon the exercise of the redemption right, we may, at our option, effect a direct exchange of cash or our Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption. Upon the redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.
Change of Control. In connection with the occurrence of a “general partner change of control” (as defined below), we have the right to require each partner of SRII Opco (other than us) to cause SRII Opco to redeem some or all of such partner’s SRII Opco Common Units and a corresponding number of shares of Class C Common Stock, in each case, effective immediately prior to the consummation of the general partner change of control. From and after the date of such redemption, the SRII Opco Common Units and shares of Class C Common Stock subject to such redemption will be deemed to be transferred to us and each such partner will cease to have any rights with respect to the SRII Opco Common Units and shares of Class C Common Stock subject to such redemption (other than the right to receive shares of Class A Common Stock pursuant to such redemption). A “general partner change of control” will be deemed to have occurred if or upon: (i) the consummation of a sale, lease or transfer of all or substantially all of our assets (determined on a consolidated basis) to any person or “group” (as such term is used in Section 13(d)(3)) that has been approved by our stockholders and board of directors, (ii) a merger or consolidation of the Company with any other person (other than a transaction in which our voting securities outstanding immediately prior to the transaction continue to represent at least 50.01% of our or the surviving entity’s total voting securities following the transaction) that has been approved by our stockholders and board of directors or (iii) subject to certain exceptions, the acquisition by any person or “group” (as such term is used in Section 13(d)(3)) of beneficial ownership of at least 50.01% of our voting securities, if recommended or approved by our board of directors or determined by our board of directors to be in our and our stockholders’ best interests.
Maintenance ofOne-to-One Ratios. The A&R LP Agreement includes provisions intended to ensure that we at all times maintain aone-to-one ratio between (a) the number of outstanding shares of Class A Common Stock and the number of SRII Opco Common Units owned by us (subject to certain exceptions for certain rights to purchase our equity securities under a “poison pill” or similar shareholder rights plan, if any, certain convertible or exchangeable securities issued under our equity compensation plans and certain equity securities issued pursuant to our equity compensation plans (other than a stock option plan) that are restricted or have not vested thereunder) and (b) the number of outstanding shares of our Class C Common Stock and the number of SRII Opco Common Units owned by the Contributors. This construct is intended to result in the Contributors having a voting interest in us that is identical to the Contributors’ economic interest in SRII Opco.
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Transfer Restrictions. The A&R LP Agreement generally does not permit transfers of SRII Opco Common Units by partners, subject to limited exceptions. Any transferee of SRII Opco Common Units must assume, by operation of law or written agreement, all of the obligations of a transferring partner with respect to the transferred units, even if the transferee is not admitted as a partner of SRII Opco.
Dissolution. The A&R LP Agreement provides that the unanimous consent of all partners will be required to voluntarily dissolve SRII Opco. In addition to a voluntary dissolution, SRII Opco will be dissolved upon a change of control transaction under certain circumstances, as well as upon the entry of a decree of judicial dissolution or other circumstances in accordance with Delaware law. Upon a dissolution event, the proceeds of a liquidation will be distributed in the following order: (i) first, to pay the expenses of winding up SRII Opco; (ii) second, to pay debts and liabilities owed to creditors of SRII Opco; and (iii) third, to the partnerspro-rata in accordance with their respective percentage ownership interests in SRII Opco (as determined based on the number of SRII Opco Common Units held by a partner relative to the aggregate number of all outstanding SRII Opco Common Units).
Confidentiality. Each partner has agreed to maintain the confidentiality of SRII Opco’s confidential information. This obligation excludes information independently obtained or developed by the partners, information that is in the public domain or otherwise disclosed to a partner, in either such case not in violation of a confidentiality obligation or disclosures required by law or judicial process or approved by our chief executive officer.
Indemnification and Exculpation. The A&R LP Agreement provides for indemnification of the General Partner and the officers and managers of the General Partner and their respective subsidiaries or affiliates and provides that, except as otherwise provided therein, we, as the general partner of SRII Opco, have the same fiduciary duties to SRII Opco and its partners as are owed to a corporation organized under Delaware law and its stockholders by its directors.
Registration Rights Agreements
On March 23, 2017, we entered into a registration rights agreement (the “Sponsor Registration Rights Agreement”) with our Sponsor and certain of our former and current directors, pursuant to which such parties are entitled to certain registration rights relating to (i) shares of our Class A Common Stock issued to our Sponsor and such former and current directors upon the conversion of their founder shares at the Closing and (ii) the Private Placement Warrants and warrants that may be issued upon conversion of working capital loans (and any shares of Class A Common Stock issuable upon the exercise of such warrants). In connection with the Closing, we and the Contributors entered into a Registration Rights Agreement (the “Business Combination Registration Rights Agreement” and, collectively with the Sponsor Registration Rights Agreement, the “Registration Rights Agreements”), pursuant to which we will be required to register for resale shares of Class A Common Stock issuable upon the future redemption or exchange of SRII Opco Common Units by the Contributors (collectively the “Contributor Shares”). Under the Forward Purchase Agreement, we are required to, within 30 calendar days after consummation of the Transactions, file the registration statement of which this prospectus forms a part registering the resale of the securities issued to Fund VI Holdings thereunder.
The holders of a majority of the Registrable Securities (as defined in the Sponsor Registration Rights Agreement) under the Sponsor Registration Rights Agreement are entitled to make up to three demands, excluding short form demands, that we register the resale of such securities. Under the Business Combination Registration Rights Agreement, we are required to, within 30 calendar days after consummation of the Transactions, file the registration statement of which this prospectus forms a part registering the resale of the Contributor Shares. Additionally, under the Business Combination Registration Rights Agreement, the Alta Mesa Contributor is entitled to demand six underwritten offerings, the Riverstone Contributoris entitled to demand three underwritten offerings and the Kingfisher Contributor is entitled to demand one underwritten offering, in each case if the offering is reasonably expected to result in gross proceeds of more than $50 million.
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The holders under the Registration Rights Agreements also have certain “piggy-back” registration rights with respect to registration statements and rights to require us to register for resale such securities pursuant to Rule 415 under the Securities Act. However, the Sponsor Registration Rights Agreement provides that we will not permit any registration statement filed under the Securities Act with respect to the founder shares and the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants to become effective until termination of the applicablelock-up period, which occurs (i) in the case of the founder shares, on the earlier of (A) March 29, 2018, (B) if the last sale price of our Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any30-trading day period commencing at least 150 days after the Closing Date, or (C) the date on which we complete a liquidation, merger, capital stock exchange, reorganization or other similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property and (ii) in the case of the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants, February 9, 2018.
We will bear the expenses incurred in connection with the filing of any such registration statements.
Series A Certificate of Designation
Upon the Closing, we filed with the Secretary of State of the State of Delaware the Certificate of Designation of Series A Preferred Stock which sets forth the terms, rights, obligations and preferences of the Series A Preferred Stock that was issued to Bayou City, HPS, and AM Management, at the Closing.
Bayou City, HPS and AM Management own the only outstanding shares of our Series A Preferred Stock and may not transfer the Series A Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the SRII Opco LPA). The holders of the Series A Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to any dividends from us but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series A Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
The Series A Preferred Stock is not convertible into any other security of the Company, but is redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series A Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series A Preferred Stock remains outstanding, the holders of the Series A Preferred Stock are entitled to nominate and elect directors to our board of directors for a period of five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Bayou City and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ (unless the director to be nominated is William W. McMullen who need not be independent) | |
HPS and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ | |
AM Management and its affiliates | ||
• at least 10% | two directors who need not be independent for purposes of the listing rules of NASDAQ |
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Holder / Beneficial Ownership and Other Requirements | Designation Right | |
• less than 10% but at least 5% and either Hal Chappelle or Michael Ellis is a member of our management | one director who need not be independent for purposes of the listing rules of NASDAQ |
The vote of Bayou City, HPS and AM Management will be the only vote required to elect such nominees to the board of directors (each such director, in such capacity, a “Series A Director”). So long as the Series A Preferred Stock remains outstanding, vacancies on our board of directors resulting from the death, resignation, retirement, disqualification or removal of a Series A Director will be filled only by the affirmative vote of the holder of the Series A Preferred Stock. We will have the right to cause the removal of the Series A Director from our board of directors immediately upon redemption of the Series A Preferred Stock as described above.
Series B Certificate of Designation
Uponthe Closing, we filed with the Secretary of State of the State of Delaware the Certificate of Designation of Series B Preferred Stock, which sets forth the terms, rights, obligations and preferences of the Series B Preferred Stock which was issued to the Riverstone Contributor at the Closing.
The Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock, and may not transfer the Series B Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the SRII Opco LPA). The holder of the Series B Preferred Stock is not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holder is not entitled to any dividends from the Company but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series B Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series B Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series B Preferred Stock remains outstanding, the holder of the Series B Preferred Stock will be entitled to nominate and elect directors to our board of directors for a period of five years following the Closing based on its and its affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Riverstone Contributor and its affiliates | ||
• at least 15% | three directors (one of whom will be the Chairman of the Board) | |
• less than 15% but at least 10% | two directors (one of whom will be the Chairman of the Board) | |
• less than 10% but at least 5% | one director (who may be the Chairman of the Board if such person is Jim Hackett) |
The vote of the Riverstone Contributor will be the only vote required to elect such nominees to the board of directors (each such director, in such capacity, a “Series B Director”). So long as the Series B Preferred Stock remains outstanding, vacancies on our board of directors resulting from the death, resignation, retirement, disqualification or removal of a Series B Director will be filled only by the affirmative vote of the holder of the Series B Preferred Stock. We will have the right to cause the removal of the Series B Director from our board of directors immediately upon redemption of the Series B Preferred Stock as described above.
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Management Services Agreement
In connection with the Closing, Alta Mesa entered into a management services agreement (the “Management Services Agreement”) with High Mesa. Under the Management Services Agreement, during the180-day period following the Closing (the “Initial Term”), Alta Mesa will provide certain administrative, management and operational services necessary to manage the business of High Mesa and its subsidiaries (the “Services”), in each case, subject to and in accordance with an approved budget. Thereafter, the Management Services Agreement shall automatically renew for additional consecutive180-day periods (each a “Renewal Term”), unless terminated by either party upon at least90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. For a period of 60 days following the expiration of the term, Alta Mesa is obligated to assist High Mesa with the transition of the Services from Alta Mesa to a successor service provider. As compensation for the Services, including during any transition to a successor service provider, High Mesa will pay Alta Mesa each month (i) a management fee of $10,000, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses incurred in connection with any emergency
Alta Mesa is obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and gas industry, and in material compliance with all applicable laws; provided that Alta Mesa will only be liable under the Management Services Agreement for its own gross negligence, willful misconduct and/or fraud. Alta Mesa is only obligated to provide the Services under the Management Services Agreement to the extent that High Mesa has provided the funds necessary to undertake such Services.
Under the Management Services Agreement, High Mesa will have customary audit rights that will survive the termination or expiration of the Management Services Agreement. Each of High Mesa and Alta Mesa will have rights to terminate the Management Services Agreement prior to the expiration of the term (i) in the event of a sale or change of control of the other party, (ii) following an event related to bankruptcy of either party or (iii) following the other party’s material breach. In addition, High Mesa will have the right to terminate the Management Services Agreement prior to the expiration of the term upon a sale or change of control of High Mesa.
Tax Receivable Agreement
As described in “Risk Factors—Risks Related to the Company and the Business Combination” above, in the future, each of the TRA Holders may exchange their SRII Opco Common Units for shares of our Class A Common Stock (on aone-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) or for cash in certain circumstances, pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA. SRII Opco will have in effect an election under Section 754 of Internal Revenue Code of 1986, as amended (the “Code”) for itself (and for each of its direct or indirect subsidiaries that is treated as a partnership for U.S. federal income tax purposes) effective for each taxable year in which an exchange of SRII Opco Common Units for shares of Class A Common Stock or cash occurs. Pursuant to this election under Section 754 of the Code, each future exchange of SRII Opco Common Units for Class A Common Stock or cash is expected to result in an adjustment to the tax basis of the tangible and intangible assets of SRII Opco, and these adjustments will be allocated to us. Adjustments to the tax basis of the tangible and intangible assets of SRII Opco described above would not have been available to us absent these exchanges of SRII Opco Common Units. The anticipated basis adjustments are expected to increase (for tax purposes) our share of the depreciation, depletion and amortization deductions of SRII Opco and may also decrease our gains (or increase our losses) on future dispositions of certain SRII Opco capital assets to the extent tax basis is allocated to those capital assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that we would otherwise be required to pay in the future.
At the Closing, we entered into the Tax Receivable Agreement with SRII Opco and the Initial Limited Partners. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if
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any, in U.S. federal, state and local income tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by Kingfisher or otherwise used in Kingfisher’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings.
The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of SRII Opco, and we expect that the payments we will be required to make under the Tax Receivable Agreement may be substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been entitled to any of the tax benefits subject to the Tax Receivable Agreement. In other words, we would calculate our federal, state and local income liabilities as if no tax attributes arising from a redemption or direct exchange of SRII Opco Common Units had been transferred to us. The term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or have expired, unless we exercise our right to terminate the Tax Receivable Agreement or the Tax Receivable Agreement is otherwise terminated.
The actual increase in tax basis will vary depending upon the timing of the exchanges, the price of Class A Common Stock at the time of each exchange, the extent to which such exchanges are taxable transactions and the amount of the exchanging TRA Holder’s tax basis in its SRII Opco Common Units at the time of the relevant exchange. The amount of such cash payments is also based on the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable and the portion of our payments under the Tax Receivable Agreement that constitute interest or give rise to depreciable or amortizable tax basis. Accordingly, we are not able to estimate the actual amount of payments that would be expected under the Tax Receivable Agreement. However, we expect that the payments that we will be required to make under the Tax Receivable Agreement could be material based on certain assumptions, including as to the matters described above. Moreover, there may be a negative impact on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the Tax Receivable Agreement exceed the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement and/or (ii) distributions to us by SRII Opco are not sufficient to permit us to make payments under the Tax Receivable Agreement after we have paid our taxes and other obligations. Please see “Risk Factors—Risks Related to the Company and the Business Combination—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.” The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either SRII Opco or us.
In addition, the TRA Holders will not reimburse us for any cash payments previously made under the Tax Receivable Agreement if any tax benefits initially claimed by us are challenged by the IRS or other relevant tax authority and are ultimately disallowed, except that excess payments made to TRA Holders will be netted against payments otherwise to be made, if any, to the TRA Holders after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.
Additionally, if the Tax Receivable Agreement terminates early (at our election or as a result of our material breach of our obligations under the Tax Receivable Agreement, whether as a result of our failure to make any payment when due, failure to honor any other material obligation under it or by operation of law as a result of the rejection of the Tax Receivable Agreement in a case commenced under the United States Bankruptcy Code or otherwise), we would be required to make a substantial, immediatelump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (calculated using a discount rate of 18%). The calculation of the hypothetical future
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payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including that (i) we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement, (ii) all taxable income of the Company is subject to the maximum applicable tax rates throughout the relevant period and (iii) certain loss or credit carryovers will be utilized through the expiration date of such carryovers.
Any payment upon early termination may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the payment obligation relates. Because of the deductions and other tax incentives available to us with respect to oil and natural gas exploration and production, our ability to generate net taxable income in the future is subject to substantial uncertainty. Accordingly, our ability to use the tax benefits covered by the Tax Receivable Agreement may be significantly delayed, and such tax benefits may expire before we are able to utilize them. Except in the event of an early termination, we generally will not be obligated to make a payment under the Tax Receivable Agreement with respect to any tax benefits that we are unable to utilize.
Assuming no material changes in the relevant tax law, we expect that if the Tax Receivable Agreement was terminated immediately after the Business Combination, the estimated termination payments, based on the assumptions discussed herein and certain other assumptions, would be approximately $83.9 million (calculated using a discount rate equal to 18%). The foregoing amounts are merely estimates, and the actual payments could differ materially. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the Tax Receivable Agreement payments as compared to the foregoing estimates.
Decisions we make in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes in control, may influence the timing and amount of payments that are received by the TRA Holders under the Tax Receivable Agreement. For example, the earlier disposition of assets following an exchange of SRII Opco Common Units may accelerate payments under the Tax Receivable Agreement and increase the present value of such payments, and the disposition of assets before an exchange of SRII Opco Common Units may increase the TRA Holders’ tax liability without giving rise to any rights to receive payments under the Tax Receivable Agreement. Such effects may result in differences or conflicts of interest between the interests of TRA Holders and other stockholders.
Payments will generally be due under the Tax Receivable Agreement within 30 days following the finalization of the schedule with respect to which the payment obligation is calculated, although interest on such payments will begin to accrue from the due date (without extensions) of such tax return until such payment due date at a rate equal to LIBOR, plus 100 basis points. Except in cases where we elect to terminate the Tax Receivable Agreement early or we have available cash but fail to make payments when due, generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest at a rate of LIBOR plus 500 basis points; provided, however, that interest will accrue at a rate of LIBOR plus 100 basis points if we are unable to make such payment as a result of limitations imposed by existing credit agreements.
Because we are a holding company with no operations of our own, our ability to make payments under the Tax Receivable Agreement is dependent on the ability of SRII Opco to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement; this ability, in turn, may depend on the ability of SRII Opco’s subsidiaries to make distributions to it. The ability of SRII Opco and its subsidiaries to make such distributions will be subject to, among other things, the applicable provisions of Delaware law that may limit the amount of funds available for distribution and restrictions in relevant debt instruments issued by SRII Opco and/or its subsidiaries. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid.
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Pre-Closing Assignment Agreement
Prior to the Closing, Alta Mesa entered into the Assignment Agreement to transfer to its existing owners (other than the Riverstone Contributor) its remainingnon-STACK assets pursuant to the terms of the Alta Mesa Contribution Agreement, and such existing owners agreed to indemnify Alta Mesa for any losses relating to employment, environmental and tax liabilities of suchnon-STACK assets.
Voting Agreement
Certain existing owners of Alta Mesa, including Mr. Chappelle, Mr. Ellis and certain affiliates of Bayou City and HPS, own an aggregate 10% voting interest in Alta Mesa GP and will continue to own such interest following the Closing. These existing owners were a party to a voting agreement with the Alta Mesa Contributor and Alta Mesa GP, pursuant to which they have agreed to vote their interests in Alta Mesa GP as directed by the Alta Mesa Contributor. In connection with the Closing, the parties amended and restated the voting agreement to include SRII Opco as a party and the existing owners agreed to vote their interests in Alta Mesa GP as directed by SRII Opco and appoint SRII Opco as their respective proxy andattorney-in-fact with respect to any voting matters related to their respective interests in Alta Mesa GP. The voting agreement will continue in force until SRII Opco elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in Alta Mesa GP.
Restrictive Covenant Agreement
Upon the Closing, we entered into a Restrictive Covenant Agreement with ARM, the operator of Kingfisher’s assets, pursuant to which ARM agreed to not conduct certain midstream services in Kingfisher, Garfield, Major, Blaine and Logan Counties, Oklahoma and certain townships in Canadian County, Oklahoma.
Transition Services Agreement
Upon the Closing, Kingfisher entered into an operating transition services agreement (the “Transition Services Agreement”) with ARM. Under the Transition Services Agreement, during thesix-month period following the Closing, ARM will provide certain operational services with respect to certain gas gathering and processing systems and crude oil gathering facilities that are owned, or may be acquired, by Kingfisher in Kingfisher County, Oklahoma (the “TSA Services”), in each case, subject to and in accordance with an approved budget. As compensation for the TSA Services, Kingfisher will pay ARM each month (i) a management fee of $10,000, (ii) an amount equal to ARM’s costs and expenses incurred in connection with providing the TSA Services as provided for in the approved budget and (iii) an amount equal to ARM’s costs and expenses incurred in connection with any emergency.
ARM is obligated to provide the TSA Services in a good and workmanlike manner, in accordance with: (i) reasonable, customary and prudent practices in the oil and gas industry for performing services similar in scope and nature to the TSA Services and (ii) all applicable laws; provided that ARM will only be liable under the Transition Services Agreement for its own gross negligence, willful misconduct and/or fraud.
Under the Transition Services Agreement, we have customary audit rights that will survive the termination or expiration of the Transition Services Agreement, and ARM is required to provide certain monthly reports, including unaudited financial statements and reports relative to the business of Kingfisher. Each of Kingfisher and ARM have rights to terminate the Transition Services Agreement prior to the expiration of the term (i) in the event of an extended force majeure event or (ii) following the other party’s material breach. In addition, we have the right to terminate the Transition Services Agreement prior to the expiration of the term upon 60 days’ notice given by ARM.
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Related Party Policy
Prior to the closing of our IPO, we did not have a formal policy for the review, approval or ratification of related party transactions. Accordingly, certain of the transactions discussed above were not reviewed, approved or ratified in accordance with any such policy.
We have adopted a code of ethics requiring us to avoid, wherever possible, all conflicts of interests, except under guidelines or resolutions approved by our board of directors (or the appropriate committee of our board) or as disclosed in our public filings with the SEC. Under our code of ethics, conflict of interest situations include any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) involving the company. A copy of our code of ethics is available on our website.
In addition, our Audit Committee, pursuant to its charter, is responsible for reviewing and approving related party transactions to the extent that we enter into such transactions. An affirmative vote of a majority of the members of the Audit Committee present at a meeting at which a quorum is present is required in order to approve a related party transaction. A majority of the members of the entire Audit Committee will constitute a quorum. Without a meeting, the unanimous written consent of all of the members of the Audit Committee will be required to approve a related party transaction. A copy of the Audit Committee charter is available on our website. We also require each of our directors and executive officers to complete a directors’ and officers’ questionnaire that elicits information about related party transactions.
These procedures are intended to determine whether any such related party transaction impairs the independence of a director or presents a conflict of interest on the part of a director, employee or officer.
Our Audit Committee will review on a quarterly basis any payments that are made to our Sponsor, officers or directors, or our or their affiliates.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information known to the Company regarding ownership of shares of voting securities of the Company, which consists of Class A Common Stock and Class C Common Stock, as of February 12, 2018:
• | each person who is known by the Company to own beneficially more than 5% of the outstanding shares of the Company’s voting securities; |
• | each of the Company’s current executive officers and directors; and |
• | all current executive officers and directors of the Company, as a group. |
Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security or has the right to acquire such securities within 60 days, including options and warrants that are currently exercisable or exercisable within 60 days.
The beneficial ownership of voting securities of the Company is based on 382,774,128 shares of Class A Common Stock and Class C Common Stock issued and outstanding in the aggregate as of February 12, 2018.
Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all shares of voting securities beneficially owned by them.
Name and Address of Beneficial Owners(1) | Number of Shares of Voting Securities | Percent of Class % | ||||||
5% or Greater Stockholders | ||||||||
Investment vehicles affiliated with Riverstone Holdings(2) | 85,776,000 | 22.4 | % | |||||
Highfields Capital Management(3) | 11,500,000 | 3.0 | % | |||||
Orbis Allan Gray LTD(4) | 11,286,508 | 2.9 | % | |||||
Baupost Group LLC(5) | 6,615,552 | 1.7 | % | |||||
High Mesa Holdings, LP(6)(8) | 138,402,398 | 36.2 | % | |||||
KFM Holdco, LLC(7)(8) | 55,000,000 | 14.4 | % | |||||
Directors and Executive Officers | ||||||||
James T. Hackett | — | — | ||||||
Harlan H. Chappelle | — | — | ||||||
Michael E. Ellis(6)(8) | — | — | ||||||
Michael A. McCabe | — | — | ||||||
David M. Leuschen(2) | — | — | ||||||
Pierre F. Lapeyre, Jr.(2) | — | — | ||||||
William W. McMullen | — | — | ||||||
Don Dimitrievich | — | — | ||||||
William D. Gutermuth | 33,000 | * | ||||||
Jeffrey H. Tepper | 33,000 | * | ||||||
Diana J. Walters | 33,000 | * | ||||||
Donald R. Sinclair | — | — | ||||||
David Murrell | — | — | ||||||
Homer “Gene” Cole | — | — | ||||||
Ronald J. Smith | — | — | ||||||
All directors and executive officers, as a group (15 individuals) | 99,000 | * |
* | Less than one percent. |
(1) | Unless otherwise noted, the business address of each of the following entities or individuals is c/o Alta Mesa Resources, Inc., 15021 Katy Freeway, Suite 400, Houston, Texas 77094. |
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(2) | Includes 16,548,894 shares of Class A Common Stock held of record by the Sponsor, 18,522,000 shares of Class A Common Stock held of record by Riverstone VI SR II Holdings, L.P. (“SR II Holdings”), 25,857,148 shares of Class A Common Stock held by Riverstone AMR Partners, L.P. (“AMR Partners”), 1,720,243 shares of Class A Common Stock held of record by Riverstone AMR Partners-U, LLC (“AMR Partners-U”), 3,127,715 shares of Class A Common Stock held of record by Riverstone AMR Partners-T, L.P. (“AMR Partners-T”) and 20,000,000 shares of Class C Common Stock held of record by Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone Contributor” and, together with the Sponsor, SR II Holdings, AMR Partners, AMR Partners-U and AMR Partners-T, the “Riverstone Funds”). David M. Leuschen and Pierre F. Lapeyre, Jr. are the managers of Riverstone Management Group, L.L.C. (“Riverstone Management”), which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P. (“Riverstone/Gower”), which is the sole member of Riverstone Holdings LLC (“Holdings”), which is the sole shareholder of Riverstone Energy GP VI Corp, which is the managing member of Riverstone Energy GP VI, LLC (“Riverstone Energy GP’”) which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of AMR Partners, the manager of AMR Partners-U and the managing member of Riverstone Energy VI Holdings GP, LLC, which is the general partner of each of the Riverstone Contributor and SR II Holdings, which is the sole and managing member of Silver Run. Riverstone Energy GP is also the sole member of Riverstone Energy Partners VI (Non-U.S.), LLC, which is the general partner of AMR Partners-T, L.P. Riverstone Energy GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, E. Bartow Jones, N. John Lancaster, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy GP, Riverstone Energy GP VI Corp, Holdings, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by the Riverstone Funds. Each such entity or person disclaims any such beneficial ownership. The business address of each of these entities and individuals is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019. |
(3) | Based on information contained in Schedule 13G filed on April 4, 2017 by Highfields Capital Management LP (“Highfields”). Highfields’ address is 200 Clarendon Street, 59th Floor, Boston, Massachusetts 02116. |
(4) | Based on information contained in Schedule 13G filed on April 10, 2017 by Orbis Investment Management Limited (“OIML”) and Orbis Investment Management (U.S.), LLC (“OIMUS”). OIML’s address is Orbis House, 25 Front Street, Hamilton Bermuda HM11 and OIMUS’s address is 600 Montgomery Street, Suite 3800, San Francisco, CA 94111, USA. |
(5) | Based on information contained on Form 13F filed on August 11, 2017 by Baupost Group L.L.C. (“Baupost”). Baupost’s address is 10 St James Avenue, Suite 1700, Boston, MA 02116. |
(6) | The sole general partner of the Alta Mesa Contributor is High Mesa Holdings GP, LLC (“High Mesa GP”). High Mesa, Inc. (“High Mesa”) holds a majority of the outstanding limited partner interests in the Alta Mesa Contributor and all of the outstanding limited liability company interests in High Mesa GP. The interests of the Alta Mesa Contributor are beneficially owned (either directly or through interests in High Mesa) by three groups, each consisting of affiliated parties: (i) AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc., Harlan H. Chappelle, Gene Cole, Mike McCabe, Dale Hayes, AM Equity Holdings, LP and MME Mission Hope, LLC (collectively, the “Management Holders”), (ii) HPS Investment Partners, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company for its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP,KCK-AMIH, Ltd. and United Insurance Company of America, Jade Real Assets Fund, L.P. (collectively, the “HPS Alta Mesa Holders”) and (iii) Bayou City Energy Management, LLC,BCE-MESA Holdings, LLC, andBCE-AMH Holdings, LLC (collectively, the “Bayou City Holders”). The Class C Common Stock owned by the Alta Mesa Contributor is subject to a voting agreement pursuant to which the Alta Mesa Contributor will vote the shares of Class C Common Stock proportionately in accordance with the express direction of the HPS Alta Mesa Holders, the Bayou City Holders and the Management Holders, respectively, based upon the relative ownership in the Alta Mesa Contributor of each such group. Mr. Ellis (who is our Chief Operating Officer—Upstream and one of our directors), through his ownership in AM MME Holdings, LP, Galveston Bay Resources |
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Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc. and AM Equity Holdings, LP, will effectively control the vote of the Management Holders, and as a result, may be deemed to beneficially own the Class C Common Stock beneficially owned by each such entity. William W. McMullen (who is one of our directors) through his ownership of the Bayou City Holders may be deemed to beneficially own the shares beneficially owned by the Bayou City Holders. Mr. Ellis, Mr. McMullen, the Management Holders, the HPS Alta Mesa Holders and the Bayou City Holders disclaim beneficial ownership of the shares of the Alta Mesa Contributor and the other Alta Mesa Contributor holders except to the extent of their respective pecuniary interests therein. |
(7) | The members of the Kingfisher Contributor are(i) ARM-M I, LLC, a Delaware limited liability company (“ARMMI”), (ii) HMS Kingfisher HoldCo, LLC, a Delaware limited liability company (“HMS”), and (iii) Mezzanine Partners II Delaware Subsidiary, LLC, a Delaware limited liability company, KFM Offshore, LLC, a Delaware limited liability company, KFM Institutional, LLC, a Delaware limited liability company, AP Mezzanine Partners II, L.P., a Delaware limited partnership, and Jade Real Assets Fund, L.P., a Delaware limited partnership, each of which is directly or indirectly managed by HPS Investment Partners, LLC (collectively, the “HPS Kingfisher Holders”). ARMMI, HMS and the HPS Kingfisher Holders disclaim beneficial ownership of the shares held by the Kingfisher Contributor, except to the extent of their respective pecuniary interests therein. The business address of the Kingfisher Contributor is 20329 State Highway 249, Suite 450, Houston, Texas, 77070. |
(8) | Reflects shares of Class C Common Stock. |
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The selling stockholders may offer and sell, from time to time, any or all of the shares of Class A Common Stock being offered for resale by this prospectus. The term “selling stockholders” includes the stockholders listed in the table below and their permitted transferees. The shares being registered by the registration statement of which this prospectus forms a part are required to be registered pursuant to the agreements under which the securities were issued.
The following table provides, as of February 12, 2018, information regarding the beneficial ownership of our Class A Common Stock and Class C Common Stock held by each selling stockholder, the number of shares of Class A Common Stock that may be sold by each selling stockholder under this prospectus and that each selling stockholder will beneficially own after this offering.
Because each selling stockholder may dispose of all, none or some portion of their securities, no estimate can be given as to the number of securities that will be beneficially owned by a selling stockholder upon termination of this offering. For purposes of the table below, however, we have assumed that after termination of this offering none of the securities covered by this prospectus will be beneficially owned by the selling stockholders and further assumed that the selling stockholders will not acquire beneficial ownership of any additional securities during the offering. In addition, the selling stockholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, our securities in transactions exempt from the registration requirements of the Securities Act after the date on which the information in the table is presented.
We may amend or supplement this prospectus from time to time in the future to update or change this selling stockholders list and the securities that may be resold.
Please see the section entitled “Plan of Distribution” for further information regarding the stockholders’ method of distributing these shares.
Number of Shares of Common Stock Owned Prior to Offering | Maximum Number of Shares of Class A Common Stock to be Sold Pursuant to this Prospectus | Number of Shares of Class A Common Stock Owned After Offering | ||||||||||||||
Name of Selling Stockholder (1) | Class A Common Stock | Class C Common Stock | ||||||||||||||
Investment vehicles affiliated with Riverstone Holdings(2) | 65,776,000 | 20,000,000 | 88,466,666 | 25,776,000 | ||||||||||||
High Mesa Holdings, LP(3) | 0 | 138,402,398 | 189,880,572 | — | ||||||||||||
KFM Holdco, LLC(4) | 0 | 55,000,000 | 68,392,857 | — |
* | Less than one percent. |
(1) | Unless otherwise noted, the business address of each of the following entities or individuals is c/o Alta Mesa Resources, Inc., 15021 Katy Freeway, Suite 400, Houston, Texas 77094. |
(2) | Number of shares of Class A Common Stock and Class C Common Stock owned prior to offering includes 16,548,894 shares of Class A Common Stock held of record by Silver Run Sponsor II, LLC (the “Sponsor”), 18,522,000 shares of Class A Common Stock held of record by Riverstone VI SR II Holdings, L.P. (“SR II Holdings”), 25,857,148 shares of Class A Common Stock held by Riverstone AMR Partners, L.P. (“AMR Partners”), 1,720,243 shares of Class A Common Stock held of record by Riverstone AMR Partners-U, LLC (“AMR Partners-U”), 3,127,715 shares of Class A Common Stock held of record by Riverstone AMR Partners-T, L.P. (“AMR Partners-T”) and 20,000,000 shares of Class C Common Stock held of record by Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone Contributor” and, together with the Sponsor, SR II Holdings, AMR Partners, AMR Partners-U and AMR Partners-T, the “Riverstone Funds”). Maximum number of shares of Class A Common Stock to be sold pursuant to this prospectus includes 9,716,012 shares of Class A Common Stock underlying Private Placement Warrants held of record by the Sponsor, 31,855,333 shares of Class A Common Stock (including 13,333,333 shares of Class A Common Stock underlying Forward Purchase Warrants) held of |
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record by SR II Holdings, 22,648,880 shares of Class A Common Stock (including 4,561,992 shares of Class A Common Stock underlying Private Placement Warrants) held by AMR Partners, 1,506,802 shares of Class A Common Stock (including 303,504 shares of Class A Common Stock underlying Private Placement Warrants) held of record by AMR Partners-U and 2,739,639 shares of Class A Common Stock (including 551,825 shares of Class A Common Stock underlying Private Placement Warrants) held of record by AMRPartners-T. Number of shares of Class A Common Stock owned after this offering includes 16,548,894 shares of Class A Common Stock held of record by the Sponsor, 7,770,260 shares of Class A Common Stock held by AMR Partners, 516,945 shares of Class A Common Stock held of record by AMR Partners-U and 939,901 shares of Class A Common Stock held of record by AMRPartners-T. David M. Leuschen and Pierre F. Lapeyre, Jr. are the managers of Riverstone Management Group, L.L.C. (“Riverstone Management”), which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P. (“Riverstone/Gower”), which is the sole member of Riverstone Holdings LLC (“Holdings”), which is the sole shareholder of Riverstone Energy GP VI Corp, which is the managing member of Riverstone Energy GP VI, LLC (“Riverstone Energy GP’”) which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of AMR Partners, the manager of AMR Partners-U and the managing member of Riverstone Energy VI Holdings GP, LLC, which is the general partner of each of the Riverstone Contributor and SR II Holdings, which is the sole and managing member of Silver Run. Riverstone Energy GP is also the sole member of Riverstone Energy Partners VI (Non-U.S.), LLC, which is the general partner of AMR Partners-T, L.P. Riverstone Energy GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, E. Bartow Jones, N. John Lancaster, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy GP, Riverstone Energy GP VI Corp, Holdings, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by the Riverstone Funds. Each such entity or person disclaims any such beneficial ownership. The business address of each of these entities and individuals is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019. |
(3) | The sole general partner of the Alta Mesa Contributor is High Mesa Holdings GP, LLC (“High Mesa GP”). High Mesa, Inc. (“High Mesa”) holds a majority of the outstanding limited partner interests in the Alta Mesa Contributor and all of the outstanding limited liability company interests in High Mesa GP. The interests of the Alta Mesa Contributor are beneficially owned (either directly or through interests in High Mesa) by three groups, each consisting of affiliated parties: (i) AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc., Harlan H. Chappelle, Gene Cole, Mike McCabe, Dale Hayes, AM Equity Holdings, LP and MME Mission Hope, LLC (collectively, the “Management Holders”), (ii) HPS Investment Partners, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company for its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP,KCK-AMIH, Ltd. and United Insurance Company of America, Jade Real Assets Fund, L.P. (collectively, the “HPS Alta Mesa Holders”) and (iii) Bayou City Energy Management, LLC,BCE-MESA Holdings, LLC, andBCE-AMH Holdings, LLC (collectively, the “Bayou City Holders”). The Class C Common Stock owned by the Alta Mesa Contributor is subject to a voting agreement pursuant to which the Alta Mesa Contributor will vote the shares of Class C Common Stock proportionately in accordance with the express direction of the HPS Alta Mesa Holders, the Bayou City Holders and the Management Holders, respectively, based upon the relative ownership in the Alta Mesa Contributor of each such group. Mr. Ellis (who is our Chief Operating Officer—Upstream and one of our directors), through his ownership in AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc. and AM Equity Holdings, LP, will effectively control the vote of the Management Holders, and as a result, may be deemed to beneficially own the Class C Common Stock beneficially owned by each such entity. William W. McMullen (who is one of our directors) through his ownership of the Bayou City Holders may be deemed to beneficially own the shares beneficially owned by the Bayou City Holders. Mr. Ellis, Mr. McMullen, the Management Holders, the HPS Alta Mesa Holders and the Bayou City Holders disclaim beneficial ownership of the shares of the Alta Mesa Contributor and the other Alta Mesa Contributor holders except to the extent of their respective pecuniary interests therein. |
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(4) | The members of the Kingfisher Contributor are(i) ARM-M I, LLC, a Delaware limited liability company (“ARMMI”), (ii) HMS Kingfisher HoldCo, LLC, a Delaware limited liability company (“HMS”), and (iii) Mezzanine Partners II Delaware Subsidiary, LLC, a Delaware limited liability company, KFM Offshore, LLC, a Delaware limited liability company, KFM Institutional, LLC, a Delaware limited liability company, AP Mezzanine Partners II, L.P., a Delaware limited partnership, and Jade Real Assets Fund, L.P., a Delaware limited partnership, each of which is directly or indirectly managed by HPS Investment Partners, LLC (collectively, the “HPS Kingfisher Holders”). ARMMI, HMS and the HPS Kingfisher Holders disclaim beneficial ownership of the shares held by the Kingfisher Contributor, except to the extent of their respective pecuniary interests therein. The business address of the Kingfisher Contributor is 20329 State Highway 249, Suite 450, Houston, Texas, 77070. |
Material Relationships with Selling Stockholders
Please see “Certain Relationships and Related Party Transactions” appearing elsewhere in this prospectus for information regarding material relationships with our selling stockholders within the past three years.
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Issuance of Class A Common Stock Underlying Warrants
We are registering the issuance of shares of Class A Common Stock underlying the Public Warrants and the Private Placement Warrants. The prices at which the shares of Class A Common Stock underlying the Public Warrants and Private Placement Warrants covered by this prospectus may actually be disposed of may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices. We will receive the proceeds from the exercise of the Public Warrants and the Private Placement Warrants, but not from the sale of the underlying Class A Common Stock.
Pursuant to the terms of the Public Warrants, the shares of Class A Common Stock will be distributed to those Public Warrant holders who surrender the certificates representing the Public Warrants and provide payment of the exercise price through their brokers to our warrant agent, Continental Stock Transfer & Trust Company.
Resale of Class A Common Stock by Selling Stockholders
We are also registering the resale of shares of Class A Common Stock by the selling stockholders named herein. The selling stockholders, which as used herein includes their permitted transferees, may, from time to time, sell, transfer or otherwise dispose of any or all of their shares on NASDAQ or any other stock exchange, market or trading facility on which such shares are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices.
The selling stockholders may use any one or more of the following methods when disposing of their shares of Class A Common Stock:
• | ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers; |
• | block trades in which the broker-dealer will attempt to sell the shares as agent, but may position and resell a portion of the block as principal to facilitate the transaction; |
• | purchases by a broker-dealer as principal and resale by the broker-dealer for its account; |
• | an exchange distribution in accordance with the rules of the applicable exchange; |
• | privately negotiated transactions; |
• | in underwriting transactions; |
• | short sales; |
• | through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise; |
• | broker-dealers may agree with the selling stockholders to sell a specified number of such shares at a stipulated price; |
• | distribution to members, limited partners or stockholders of selling stockholders; |
• | a combination of any such methods of sale; and |
• | any other method permitted pursuant to applicable law. |
The selling stockholders may, from time to time, pledge or grant a security interest in some or all of the shares of Class A Common Stock owned by them and, if they default in the performance of their secured
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obligations, the pledgees or secured parties may offer and sell their shares, from time to time, under this prospectus, or under an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act amending the list of selling stockholders to include the pledgee, transferee or other successors in interest as selling stockholders under this prospectus. The selling stockholders also may transfer their shares in other circumstances, in which case the transferees, pledgees or other successors in interest will be the selling beneficial owners for purposes of this prospectus.
In connection with the sale of our Class A Common Stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of our securities in the course of hedging the positions they assume. The selling stockholders may also sell their securities short and deliver these securities to close out their short positions, or loan or pledge such securities to broker-dealers that in turn may sell these securities. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of the shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).
The aggregate proceeds to the selling stockholders from the sale of the shares offered by them will be the purchase price of the share less discounts or commissions, if any. Each of the selling stockholders reserves the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase of their shares to be made directly or through agents. We will not receive any of the proceeds from the resale of shares of Class A Common Stock being offered by the selling stockholders named herein.
The selling stockholders also may resell all or a portion of their shares in open market transactions in reliance upon Rule 144 under the Securities Act, provided that they meet the criteria and conform to the requirements of that rule.
In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholders or from purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling stockholders and any underwriters, dealers or agents participating in a distribution of the shares may be deemed to be “underwriters” within the meaning of the Securities Act, and any profit on the sale of the shares by the selling stockholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.
To the extent required, the shares of Class A Common Stock to be sold, the names of the selling stockholders, the respective purchase prices and public offering prices, the names of any agent, dealer or underwriter, and any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a post-effective amendment to the registration statement that includes this prospectus.
Blue Sky Restrictions on Resale
In order to comply with the securities laws of some states, if applicable, our shares of Class A Common Stock may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states our shares of Class A Common Stock may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.
If a selling stockholder wants to sell its shares of Class A Common Stock under this prospectus in the United States, the selling stockholders will also need to comply with state securities laws, also known as “Blue
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Sky laws,” with regard to secondary sales. All states offer a variety of exemption from registration for secondary sales. Many states, for example, have an exemption for secondary trading of securities registered under Section 12(g) of the Exchange Act or for securities of issuers that publish continuous disclosure of financial andnon-financial information in a recognized securities manual, such as Standard & Poor’s. The broker for a selling stockholder will be able to advise a selling stockholder in which states shares of Class A Common Stock are exempt from registration for secondary sales.
Any person who purchases shares of Class A Common Stock from a selling stockholder offered by this prospectus who then wants to sell such shares will also have to comply with Blue Sky laws regarding secondary sales.
When the registration statement that includes this prospectus becomes effective, and a selling stockholder indicates in which state(s) he desires to sell his shares of Class A Common Stock we will be able to identify whether it will need to register or will rely on an exemption there from.
We have advised the selling stockholders that the anti-manipulation rules of Regulation M under the Exchange Act may apply to sales of securities in the market and to the activities of the selling stockholders and their affiliates. In addition, we will make copies of this prospectus (as it may be supplemented or amended from time to time) available to the selling stockholders for the purpose of satisfying the prospectus delivery requirements of the Securities Act. The selling stockholders may indemnify any broker-dealer that participates in transactions involving the sale of their shares against certain liabilities, including liabilities arising under the Securities Act.
We have agreed to indemnify, to the extent permitted by law, the selling stockholders (and each selling stockholder’s officers and directors and each person who controls such selling stockholder) against liabilities caused by any untrue or alleged untrue statement of material fact contained in this prospectus or the registration statement of which this prospectus forms a part (including any amendment or supplement thereof) or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as the same are caused by or contained in any information furnished in writing to us by such selling stockholder expressly for use herein. We have also agreed to keep the registration statement of which this prospectus forms a part effective until the earlier of (i) the date on which all of their shares are disposed of pursuant to this prospectus; (ii) such shares shall have been otherwise transferred, new certificates for such shares not bearing a legend restricting further transfer shall have been delivered by us and subsequent public distribution of such shares shall not require registration under the Securities Act; (iii) such shares shall have ceased to be outstanding; or (iv) such shares have been sold without registration pursuant to Rule 144 promulgated under the Securities Act (“Rule 144”).
We are required to pay all fees and expenses incident to the registration of the shares of Class A Common Stock covered by this prospectus, including with regard to compliance with state securities or Blue Sky laws. Otherwise, all discounts, commissions or fees incurred in connection with the sale of shares of Class A Common Stock offered hereby will be paid by the selling stockholders.
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The Company has authorized 1,531,000,000 shares of capital stock, consisting of (a) 1,530,000,000 shares of common stock, including (i) 1,200,000,000 shares of Class A Common Stock, (ii) 50,000,000 shares of Class B Common Stock and (iii) 280,000,000 shares of Class C Common Stock and (b) 1,000,000 shares of preferred stock, including three shares of Series A Preferred Stock and one share of Series B Preferred Stock. As of February 12, 2018, there were: (a) one holder of record of Class A Common Stock and 169,371,730 shares of Class A Common Stock outstanding; (b) no holders of record of Class B Common Stock and no shares of Class B Common Stock outstanding; (c) three holders of record of Class C Common Stock and 213,402,398 shares of Class C Common Stock outstanding; (d) three holders of record of Series A Preferred Stock and three shares of Series A Preferred Stock outstanding; (e) one holder of record of Series B Preferred Stock and one share of Series B Preferred Stock outstanding; (f) one holder of the Public Warrants and 34,500,000 Public Warrants outstanding; (g) one holder of the Private Placement Warrants and 15,133,333 Private Placement Warrants outstanding; and (h) one holder of the Forward Purchase Warrants and 13,333,333 Forward Purchase Warrants outstanding.
Class A Common Stock
Holders of our Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by our stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock will vote together as a single class on all matters submitted to a vote of our stockholders, except as required by law. Unless specified in our Charter (including any certificate of designation of preferred stock) or the Bylaws, or as required by applicable provisions of the DGCL or applicable stock exchange rules, the affirmative vote of a majority of our shares of common stock that are voted is required to approve any such matter voted on by our stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holders of our Series A Preferred Stock and Series B Preferred Stock to nominate and elect up to seven directors). Subject to the rights of the holders of any outstanding series of preferred stock, our stockholders are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor.
In the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. Our stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.
Class C Common Stock
In connection with the Business Combination, we issued 213,402,398 shares of Class C Common Stock to the Contributors. Holders of Class C Common Stock, together with holders of Class A Common Stock voting as a single class, will have the right to vote on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of our Charter that would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class C Common Stock. Holders of Class C Common Stock will not be entitled to any dividends from the Company and will not be entitled to receive any of our assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
Shares of Class C Common Stock may be issued only to the Contributors, their respective successors and assigns, as well as any permitted transferees of the Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such holder’s SRII Opco Common Units to such transferee in compliance with the amended and restated limited partnership agreement of SRII Opco. The Contributors generally
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have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such SRII Opco Common Units in lieu of such a redemption by SRII Opco. Upon the future redemption or exchange of SRII Opco Common Units held by a Contributor, a corresponding number of shares of Class C Common Stock will be cancelled.
Earn-out Consideration
Pursuant to the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, for a period of seven years following the Closing, the Alta Mesa Contributor and the Kingfisher Contributor may be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) asearn-out consideration if the20-Day VWAP of the Class A Common Stock equals or exceeds specified prices as follows (each such payment, an“Earn-Out Payment”):
20-Day VWAP | Earn-Out Consideration Payable to Alta Mesa Contributor | Earn-Out Consideration Payable to Kingfisher Contributor | ||||
$14.00 | 10,714,285 SRII Opco Common Units | 7,142,857 SRII Opco Common Units | ||||
$16.00 | 9,375,000 SRII Opco Common Units | 6,250,000 SRII Opco Common Units | ||||
$18.00 | 13,888,889 SRII Opco Common Units | — | ||||
$20.00 | 12,500,000 SRII Opco Common Units | — |
Neither the Alta Mesa Contributor nor the Kingfisher Contributor will be entitled to receive a particularEarn-Out Payment on more than one occasion and, if, on a particular date, the20-Day VWAP entitles the Alta Mesa Contributor or the Kingfisher Contributor to more than oneEarn-Out Payment (each of which has not been previously paid), the Alta Mesa Contributor and/or the Kingfisher Contributor will be entitled to receive each suchEarn-Out Payment. The Alta Mesa Contributor and the Kingfisher Contributor will be entitled to theearn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of our assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified20-Day VWAP hurdles.
Series A Preferred Stock
We filed with the Secretary of State of the State of Delaware the Certificate of Designation of Series A Preferred Stock which sets forth the terms, rights, obligations and preferences of the Series A Preferred Stock issued to Bayou City, HPS, and AM Management, at the Closing of the Business Combination. Bayou City, HPS and AM Management own the only outstanding shares of our Series A Preferred Stock, and may not transfer the Series A Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the SRII Opco LPA). The holders of the Series A Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to any dividends from the Company but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series A Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
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The Series A Preferred Stock is not convertible into any other security of the Company, but will be redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series A Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series A Preferred Stock remains outstanding, the holders of the Series A Preferred Stock will be entitled to nominate and elect directors to our board of directors for a period of five years following the Closing based on their and their affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Bayou City and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ (unless the director to be nominated is William W. McMullen who need not be independent) | |
HPS and its affiliates | ||
• at least 10% | one director who must be independent for purposes of the listing rules of NASDAQ | |
AM Management and its affiliates | ||
• at least 10% | two directors who need not be independent for purposes of the listing rules of NASDAQ | |
• less than 10% but at least 5% and either Hal Chappelle or Michael Ellis is a member of our management | one director who need not be independent for purposes of the listing rules of NASDAQ |
The vote of Bayou City, HPS and AM Management will be the only vote required to elect such nominees to the board of directors (each such director, in such capacity, a “Series A Director”). So long as the Series A Preferred Stock remains outstanding, vacancies on our board of directors resulting from the death, resignation, retirement, disqualification or removal of a Series A Director will be filled only by the affirmative vote of the holder of the Series A Preferred Stock. We will have the right to cause the removal of the Series A Director from our board of directors immediately upon redemption of the Series A Preferred Stock as described above.
Series B Certificate of Designation
We filed with the Secretary of State of the State of Delaware the Certificate of Designation of Series B Preferred Stock, which sets forth the terms, rights, obligations and preferences of the Series B Preferred Stock which was issued to the Riverstone Contributor at the Closing. The Riverstone Contributor owns the only outstanding share of our Series B Preferred Stock, and may not transfer the Series B Preferred Stock or any rights, powers, preferences or privileges thereunder except to an affiliate (as defined in the SRII Opco LPA). The holder of the Series B Preferred Stock is not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holder is not entitled to any dividends from the Company but will be entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series B Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable for the par value thereof by us upon the earlier to occur of (1) the fifth anniversary of the Closing Date, (2) the optional redemption of such Series B Preferred Stock at the election of the holder thereof or (3) upon a breach of the transfer restrictions described above. For so long as the Series B Preferred Stock remains outstanding, the holder of the Series B Preferred Stock will be entitled to nominate and elect directors to our
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board of directors for a period of five years following the Closing based on its and its affiliates’ beneficial ownership of Class A Common Stock as follows:
Holder / Beneficial Ownership and Other Requirements | Designation Right | |
Riverstone Contributor and its affiliates | ||
• at least 15% | three directors (one of whom will be the Chairman of the Board) | |
• less than 15% but at least 10% | two directors (one of whom will be the Chairman of the Board) | |
• less than 10% but at least 5% | one director (who may be the Chairman of the Board if such person is Jim Hackett) |
The vote of the Riverstone Contributor will be the only vote required to elect such nominees to the board of directors (each such director, in such capacity, a “Series B Director”). So long as the Series B Preferred Stock remains outstanding, vacancies on our board of directors resulting from the death, resignation, retirement, disqualification or removal of a Series B Director will be filled only by the affirmative vote of the holder of the Series B Preferred Stock. We will have the right to cause the removal of the Series B Director from our board of directors immediately upon redemption of the Series B Preferred Stock as described above.
Warrants
Public Warrants
Each whole Public Warrant issued in our IPO entitles the registered holder to purchase one whole share of our Class A Common Stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing 12 months from the closing of our IPO. Pursuant to the warrant agreement, a warrant holder may exercise its Public Warrants only for a whole number of shares of Class A Common Stock. No fractional Public Warrants have been issued and only whole Public Warrants trade. The Public Warrants will expire February 9, 2023, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.
The Company will not be obligated to deliver any shares of Class A Common Stock pursuant to the exercise of a Public Warrant and will have no obligation to settle exercise unless the registration statement of which this prospectus forms a part is then effective and a prospectus relating thereto is current, subject to the Company satisfying its obligations described below with respect to registration. No Public Warrant will be exercisable and the Company will not be obligated to issue shares of Class A Common Stock upon exercise of a Public Warrant unless Class A Common Stock issuable upon such exercise has been registered, qualified or deemed to be exempt under the securities laws of the state of residence of the registered holder of the Public Warrants. In the event that the conditions in the two immediately preceding sentences are not satisfied with respect to a Public Warrant, the holder of such Public Warrant will not be entitled to exercise such Public Warrant and such Public Warrant may have no value and expire worthless.
Under the warrant agreement, the Company agreed that as soon as practicable, but in no event later than 15 business days, after the Closing of the Business Combination, the Company would use its best efforts to file with the SEC the registration statement of which this prospectus forms a part, for the registration, under the Securities Act, of the shares of Class A Common Stock issuable upon exercise of the Public Warrants. We have agreed to use our best efforts to cause the same to become effective and to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the expiration of the Public Warrants in accordance with the provisions of the warrant agreement. Notwithstanding the above, if the Class A Common Stock is at the time of any exercise of a Public Warrant not listed on a national securities exchange such that it satisfies the definition of a “covered security” under Section 18 (b)(1) of the Securities Act, the Company may, at its option, require holders of Public Warrants who exercise their Public Warrants to do so on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act and, in the event the Company so elects, it will not be required to file or maintain in effect a registration statement, but the Company will be required to use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.
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Once the Public Warrants become exercisable, the Company may call the Public Warrants for redemption:
• | in whole and not in part; |
• | at a price of $0.01 per Public Warrant; |
• | upon not less than 30 days’ prior written notice of redemption (the“30-day redemption period”) to each Public Warrant holder; and |
• | if, and only if, the reported last sale price of the Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a30-trading day period ending three business days before the Company sends the notice of redemption to the Public Warrant holders. |
If and when the Public Warrants become redeemable by the Company, the Company may exercise its redemption right even if it is unable to register or qualify the underlying securities for sale under all applicable state securities laws if the Company has elected to require the exercise of the Public Warrants on a cashless basis.
The Company has established the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant premium to the Public Warrant exercise price. If the foregoing conditions are satisfied and the Company issues a notice of redemption of the Public Warrants, each Public Warrant holder will be entitled to exercise its Public Warrant prior to the scheduled redemption date. However, the price of the Class A Common Stock may fall below the $18.00 redemption trigger price as well as the $11.50 Public Warrant exercise price after the redemption notice is issued.
If the Company calls the Public Warrants for redemption as described above, our management will have the option to require any holder that wishes to exercise its Public Warrant to do so on a “cashless basis.” In determining whether to require all holders to exercise their Public Warrants on a “cashless basis,” our management will consider, among other factors, its cash position, the number of Public Warrants that are outstanding and the dilutive effect on its stockholders of issuing the maximum number of shares of Class A Common Stock issuable upon the exercise of its Public Warrants. If our management takes advantage of this option, all holders of Public Warrants would pay the exercise price by surrendering their Public Warrants for that number of shares of Class A Common Stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A Common Stock underlying the Public Warrants, multiplied by the difference between the exercise price of the Public Warrants and the “fair market value” (defined below) by (y) the fair market value. The “fair market value” shall mean the average reported last sale price of the Class A Common Stock for the 10 trading days ending on the third trading day prior to the date on which the notice of redemption is sent to the holders of Public Warrants. If our management takes advantage of this option, the notice of redemption will contain the information necessary to calculate the number of shares of Class A Common Stock to be received upon exercise of the Public Warrants, including the “fair market value” in such case. Requiring a cashless exercise in this manner will reduce the number of shares to be issued and thereby lessen the dilutive effect of a Public Warrant redemption. The Company believes this feature is an attractive option to the Company if it does not need the cash from the exercise of the Public Warrants. If the Company calls its Public Warrants for redemption and its management does not take advantage of this option, our Sponsor and its permitted transferees would still be entitled to exercise their Private Placement Warrants and Forward Purchase Warrants for cash or on a cashless basis using the same formula described above that other Public Warrant holders would have been required to use had all Public Warrant holders been required to exercise their Public Warrants on a cashless basis, as described in more detail below.
A holder of a Public Warrant may notify the Company in writing in the event it elects to be subject to a requirement that such holder will not have the right to exercise such Public Warrant, to the extent that after giving effect to such exercise, such person (together with such person’s affiliates), to the warrant agent’s actual knowledge, would beneficially own in excess of 9.8% (or such other amount as a holder may specify) of the shares of Class A Common Stock outstanding immediately after giving effect to such exercise.
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If the number of outstanding shares of Class A Common Stock is increased by a stock dividend payable in shares of Class A Common Stock, or by asplit-up of shares of Class A Common Stock or other similar event, then, on the effective date of such stock dividend,split-up or similar event, the number of shares of Class A Common Stock issuable on exercise of each Public Warrant will be increased in proportion to such increase in the outstanding shares of Class A Common Stock. A rights offering to holders of Class A Common Stock entitling holders to purchase shares of Class A Common Stock at a price less than the fair market value will be deemed a stock dividend of a number of shares of Class A Common Stock equal to the product of (i) the number of shares of Class A Common Stock actually sold in such rights offering (or issuable under any other equity securities sold in such rights offering that are convertible into or exercisable for Class A Common Stock) multiplied by (ii) one (1) minus the quotient of (x) the price per share of Class A Common Stock paid in such rights offering divided by (y) the fair market value. For these purposes (i) if the rights offering is for securities convertible into or exercisable for Class A Common Stock, in determining the price payable for Class A Common Stock, there will be taken into account any consideration received for such rights, as well as any additional amount payable upon exercise or conversion and (ii) fair market value means the volume weighted average price of Class A Common Stock as reported during the 10 trading day period ending on the trading day prior to the first date on which the shares of Class A Common Stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive such rights.
In addition, if the Company, at any time while the Public Warrants are outstanding and unexpired, pays a dividend or makes a distribution in cash, securities or other assets to the holders of Class A Common Stock on account of such shares of Class A Common Stock (or other shares of our capital stock into which the Public Warrants are convertible), other than (a) as described above or (b) certain ordinary cash dividends, then the Public Warrant exercise price will be decreased, effective immediately after the effective date of such event, by the amount of cash and/or the fair market value of any securities or other assets paid on each share of Class A Common Stock in respect of such event.
If the number of outstanding shares of Class A Common Stock is decreased by a consolidation, combination, reverse stock split or reclassification of shares of Class A Common Stock or other similar event, then, on the effective date of such consolidation, combination, reverse stock split, reclassification or similar event, the number of shares of Class A Common Stock issuable on exercise of each Public Warrant will be decreased in proportion to such decrease in outstanding shares of Class A Common Stock.
Whenever the number of shares of Class A Common Stock purchasable upon the exercise of the Public Warrants is adjusted, as described above, the Public Warrant exercise price will be adjusted by multiplying the exercise price immediately prior to such adjustment by a fraction (x) the numerator of which will be the number of shares of Class A Common Stock purchasable upon the exercise of the Public Warrants immediately prior to such adjustment, and (y) the denominator of which will be the number of shares of Class A Common Stock so purchasable immediately thereafter.
In case of any reclassification or reorganization of the outstanding shares of Class A Common Stock (other than those described above or that solely affects the par value of such shares of Class A Common Stock), or in the case of any merger or consolidation of the Company with or into another corporation (other than a consolidation or merger in which the Company is the continuing corporation and that does not result in any reclassification or reorganization of our outstanding shares of Class A Common Stock), or in the case of any sale or conveyance to another corporation or entity of the assets or other property of the Company as an entirety or substantially as an entirety in connection with which the Company is dissolved, the holders of the Public Warrants will thereafter have the right to purchase and receive, upon the basis and upon the terms and conditions specified in the Public Warrants and in lieu of the shares of Class A Common Stock immediately theretofore purchasable and receivable upon the exercise of the rights represented thereby, the kind and amount of shares of stock or other securities or property (including cash) receivable upon such reclassification, reorganization, merger or consolidation, or upon a dissolution following any such sale or transfer, that the holder of the Public Warrants would have received if such holder had exercised their Public Warrants immediately prior to such
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event. If less than 70% of the consideration receivable by the holders of Class A Common Stock in such a transaction is payable in the form of common stock in the successor entity that is listed for trading on a national securities exchange or is quoted in an establishedover-the-counter market, or is to be so listed for trading or quoted immediately following such event, and if the registered holder of the Public Warrant properly exercises the Public Warrant within 30 days following public disclosure of such transaction, the Public Warrant exercise price will be reduced as specified in the warrant agreement based on the Black-Scholes value (as defined in the warrant agreement) of the Public Warrant.
The Public Warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, with the exercise form on the reverse side of the warrant certificate completed and executed as indicated, accompanied by full payment of the exercise price (or on a cashless basis, if applicable), by certified or official bank check payable to the Company, for the number of Public Warrants being exercised. The Public Warrant holders do not have the rights or privileges of holders of Class A Common Stock and any voting rights until they exercise their Public Warrants and receive shares of Class A Common Stock. After the issuance of shares of Class A Common Stock upon exercise of the Public Warrants, each holder will be entitled to one vote for each share held of record on all matters to be voted on by stockholders.
No fractional shares will be issued upon exercise of the Public Warrants. If, upon exercise of the Public Warrants, a holder would be entitled to receive a fractional interest in a share, the Company will, upon exercise, round down to the nearest whole number of shares of Class A Common Stock to be issued to the Public Warrant holder.
The Public Warrants have been issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company. The warrant agreement provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders of Public Warrants.
Private Placement Warrants
The Private Placement Warrants (including the Class A Common Stock issuable upon exercise of the Private Placement Warrants) will not be transferable, assignable or saleable until 30 days after the completion of the Business Combination (except, among other limited exceptions, to our officers and directors and other persons or entities affiliated with our Sponsor) and they will not be redeemable by the Company so long as they are held by our Sponsor or its permitted transferees. Otherwise, the Private Placement Warrants have terms and provisions that are identical to those of the Public Warrants, including as to exercise price, exercisability and exercise period. If the Private Placement Warrants are held by holders other than our Sponsor or its permitted transferees, the Private Placement Warrants will be redeemable by the Company and exercisable by the holders on the same basis as the Public Warrants.
If holders of the Private Placement Warrants elect to exercise them on a cashless basis, they would pay the exercise price in the same manner as holders of Public Warrants as described above under “—Public Warrants.” The reason that the Company has agreed that the Private Placement Warrants will be exercisable on a cashless basis so long as they are held by our Sponsor or its permitted transferees is because it was not known at the time of issuance whether our Sponsor would be affiliated with the Company following an initial business combination. If our Sponsor remains affiliated with the Company, its ability to sell our securities in the open market will be significantly limited. The Company has policies in place that prohibit insiders from selling our securities except during specific periods of time. Even during such periods of time when insiders will be permitted to sell our securities, an insider cannot trade in our securities if he or she is in possession of materialnon-public information. Accordingly, unlike public stockholders who could sell the shares of Class A Common Stock issuable upon exercise of the Public Warrants freely in the open market, the insiders could be significantly restricted from doing so. As a result, the Company believes that allowing the holders to exercise the Private Placement Warrants on a cashless basis is appropriate.
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Our Sponsor has agreed not to transfer, assign or sell any of the Private Placement Warrants (including the Class A Common Stock issuable upon exercise of any of the Private Placement Warrants) until the date that is 30 days after the Closing Date, except to, among other limited exceptions, our officers and directors and other persons or entities affiliated with our Sponsor.
The Private Placement Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor and have the terms set forth in a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company.
Forward Purchase Warrants
The Forward Purchase Warrants have terms and provisions that are identical to those of the Private Placement Warrants, including as to exercise price, exercisability and exercise period, except the Forward Purchase Warrants are not subject to thelock-up that is applicable to the Private Placement Warrants.
The Forward Purchase Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor and have the terms set forth in a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company.
Our Transfer Agent and Warrant Agent
The transfer agent for our Class A Common Stock and Class C Common Stock and warrant agent for the Public Warrants, Private Placement Warrants and Forward Purchase Warrants is Continental Stock Transfer & Trust Company. We have agreed to indemnify Continental Stock Transfer & Trust Company in its roles as transfer agent and warrant agent, its agents and each of its stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence, willful misconduct or bad faith of the indemnified person or entity.
Certain Anti-Takeover Provisions of Delaware Law and our Charter and Bylaws
We are subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. This statute prevents certain Delaware corporations, under certain circumstances, from engaging in a “business combination” with:
• | a stockholder who owns 15% or more of our outstanding voting stock (otherwise known as an “interested stockholder”); |
• | an affiliate of an interested stockholder; or |
• | an associate of an interested stockholder, for three years following the date that the stockholder became an interested stockholder. |
A “business combination” includes a merger or sale of more than 10% of our assets. However, the above provisions of Section 203 of the DGCL do not apply if:
• | our board of directors approves the transaction that made the stockholder an “interested stockholder,” prior to the date of the transaction; |
• | after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, that stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, other than statutorily excluded shares of common stock; or |
• | on or subsequent to the date of the transaction, the business combination is approved by our board of directors and authorized at a meeting of our stockholders, and not by written consent, by an affirmative vote of at leasttwo-thirds of the outstanding voting stock not owned by the interested stockholder. |
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Under our Charter, our board of directors is classified into three classes of directors. As a result, in most circumstances, a person can gain control of our board only by successfully engaging in a proxy contest at two or more annual meetings.
Our authorized but unissued common stock and preferred stock are available for future issuances without stockholder approval (including a specified future issuance) and could be utilized for a variety of corporate purposes, including future offerings to raise additional capital, acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.
Special Meeting of Stockholders
Our Bylaws provide that special meetings of our stockholders may be called only by a majority vote of our board of directors, by our Chief Executive Officer or by our Chairman of the Board.
Advance Notice Requirements for Stockholder Proposals and Director Nominations
Our Bylaws provide that stockholders seeking to bring business before our annual meeting of stockholders, or to nominate candidates for election as directors at our annual meeting of stockholders, must provide timely notice of their intent in writing. To be timely, a stockholder’s notice will need to be received by the company secretary at our principal executive offices not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the anniversary date of the immediately preceding annual meeting of stockholders. Pursuant toRule 14a-8 of the Exchange Act, proposals seeking inclusion in our annual proxy statement must comply with the notice periods contained therein. Our Bylaws also specify certain requirements as to the form and content of a stockholders’ meeting. These provisions may preclude our stockholders from bringing matters before our annual meeting of stockholders or from making nominations for directors at our annual meeting of stockholders.
Rule 144
Pursuant to Rule 144, a person who has beneficially owned restricted shares of our Class A Common Stock or warrants for at least six months would be entitled to sell their securities provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the three months preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least three months before the sale and have filed all required reports under Section 13 or 15(d) of the Exchange Act during the 12 months (or such shorter period as we were required to file reports) preceding the sale.
Persons who have beneficially owned restricted shares of our Class A Common Stock or warrants for at least six months but who are our affiliates at the time of, or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of securities that does not exceed the greater of:
• | 1% of the total number of shares of Class A Common Stock then outstanding; or |
• | the average weekly reported trading volume of the Class A Common Stock during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale. |
Sales by our affiliates under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.
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Restrictions on the Use of Rule 144 by Shell Companies or Former Shell Companies
Rule 144 is not available for the resale of securities initially issued by shell companies (other than business combination related shell companies) or issuers that have been at any time previously a shell company. However, Rule 144 also includes an important exception to this prohibition if the following conditions are met:
• | the issuer of the securities that was formerly a shell company has ceased to be a shell company; |
• | the issuer of the securities is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act; |
• | the issuer of the securities has filed all Exchange Act reports and materials required to be filed, as applicable, during the preceding 12 months (or such shorter period that the issuer was required to file such reports and materials), other than Current Reports onForm 8-K; and |
• | at least one year has elapsed from the time that the issuer filed current Form 10 type information with the Securities and Exchange Commission reflecting its status as an entity that is not a shell company. |
As a result, if we have filed all Exchange Act reports and materials as set forth in the third bullet of the preceding paragraph, then the purchasers of the founder shares, Private Placement Warrants and securities purchased pursuant to the Forward Purchase Contracts will be able to sell those securities pursuant to Rule 144 without registration one year following the completion of the Business Combination, February 9, 2019.
Listing of Securities
Our Class A Common Stock and Public Warrants are currently quoted on NASDAQ under the symbols “AMR” and “AMRWW,” respectively. Through February 9, 2018, our Class A Common Stock, Public Warrants and Units were quoted under the symbols “SRUN,” “SRUNW” and “SRUNU,” respectively. Upon the consummation of the Business Combination, we separated our Units into their component securities of one share of Class A Common Stock andone-third of one Public Warrant.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TONON-U.S. HOLDERS
The following discussion is a summary of the material U.S. federal income tax consequences toNon-U.S. Holders (as defined below) of the purchase, ownership and disposition of our Class A Common Stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local ornon-U.S. tax laws are not discussed. This discussion is based on the Code, Treasury regulations promulgated thereunder (“Treasury Regulations”), judicial decisions, and published rulings and administrative pronouncements of the IRS, in each case as in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect aNon-U.S. Holder of our Class A Common Stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our Class A Common Stock.
This discussion is limited toNon-U.S. Holders that hold our Class A Common Stock as a “capital asset” within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to aNon-U.S. Holder’s particular circumstances, including the impact of the Medicare contribution tax on net investment income. In addition, it does not address consequences relevant toNon-U.S. Holders subject to special rules, including, without limitation:
• | U.S. expatriates and former citizens or long-term residents of the United States; |
• | persons subject to the alternative minimum tax; |
• | persons holding our Class A Common Stock as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment; |
• | banks, insurance companies, and other financial institutions; |
• | brokers, dealers or traders in securities; |
• | “controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax; |
• | partnerships, or other entities or arrangements treated as partnerships for U.S. federal income tax purposes; |
• | tax-exempt organizations or governmental organizations; |
• | persons deemed to sell our Class A Common Stock under the constructive sale provisions of the Code; |
• | persons who hold or receive our Class A Common Stock pursuant to the exercise of any employee stock option or otherwise as compensation; |
• | “qualified foreign pension funds” as defined in Section 897(l)(2) of the Code and entities all of the interests of which are held by qualified foreign pension funds; and |
• | tax-qualified retirement plans. |
If an entity treated as a partnership for U.S. federal income tax purposes holds our Class A Common Stock, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our Class A Common Stock and partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.
THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE
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APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL ORNON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.
Definition of aNon-U.S. Holder
For purposes of this discussion, a“Non-U.S. Holder” is any beneficial owner of our Class A Common Stock that is neither a “U.S. person” nor an entity treated as a partnership for U.S. federal income tax purposes. A U.S. person is any person that, for U.S. federal income tax purposes, is or is treated as any of the following:
• | an individual who is a citizen or resident of the United States; |
• | a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia; |
• | an estate, the income of which is subject to U.S. federal income tax regardless of its source; or |
• | a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code), or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes. |
Distributions
As described in the section entitled “Dividend Policy” we do not anticipate declaring or paying dividends to holders of our Class A Common Stock in the foreseeable future. However, if we do make distributions of cash or property on our Class A Common Stock, such 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. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce aNon-U.S. Holder’s adjusted tax basis in its Class A Common Stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below under “—Sale or Other Taxable Disposition.”
Subject to the discussion below on effectively connected income, dividends paid to aNon-U.S. Holder of our Class A Common Stock will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided theNon-U.S. Holder furnishes a valid IRSForm W-8BEN orW-8BEN-E (or other applicable documentation) certifying qualification for the lower treaty rate). ANon-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS.Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.
If dividends paid to aNon-U.S. Holder are effectively connected with theNon-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, theNon-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), theNon-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, theNon-U.S. Holder must furnish to the applicable withholding agent a valid IRSForm W-8ECI, certifying that the dividends are effectively connected with theNon-U.S. Holder’s conduct of a trade or business within the United States.
Any such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. ANon-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected
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earnings and profits (as adjusted for certain items), which will include such effectively connected dividends.Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.
Sale or Other Taxable Disposition
ANon-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of our Class A Common Stock unless:
• | the gain is effectively connected with theNon-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, theNon-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable); |
• | theNon-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met; or |
• | our Class A Common Stock constitutes a United States real property interest (“USRPI”) by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes. Generally, a domestic corporation is a USRPHC if the fair market value of its USRPIs equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in its trade or business. |
Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. ANon-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (adjusted for certain items), which will include such effectively connected gain.
ANon-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the disposition, which may be offset by U.S. source capital losses of theNon-U.S. Holder (even though the individual is not considered a resident of the United States), provided theNon-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.
With respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, aNon-U.S. Holder of our Class A Common Stock generally will not be subject to U.S. net federal income tax as a result of our being a USRPHC if our Class A Common Stock is “regularly traded,” as defined by applicable Treasury Regulations, on an established securities market, and suchNon-U.S. Holder owned, actually or constructively, 5% or less of our Class A Common Stock throughout the shorter of the five-year period ending on the date of the sale or other taxable disposition or theNon-U.S. Holder’s holding period. If our Class A Common Stock is not considered to be so traded, aNon-U.S. Holder generally would be subject to net U.S. federal income tax on the gain realized on a disposition of our Class A Common Stock as a result of our being a USRPHC and generally would be required to file a U.S. federal income tax return. Additionally, a 15% withholding tax would apply to the gross proceeds from such disposition.
Non-U.S. Holders should also consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.
Information Reporting and Backup Withholding
Payments of dividends on our Class A Common Stock will not be subject to backup withholding, provided the applicable withholding agent does not have actual knowledge or reason to know theNon-U.S. Holder is a
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United States person and theNon-U.S. Holder either certifies itsnon-U.S. status, such as by furnishing a valid IRSForm W-8BEN,W-8BEN-E orW-8ECI, or otherwise establishes an exemption. However, information returns are required to be filed with the IRS in connection with any dividends on our Class A Common Stock paid to theNon-U.S. Holder, regardless of whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of our Class A Common Stock within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that suchNon-U.S. Holder is a United States person, or theNon-U.S. Holder otherwise establishes an exemption. Proceeds of a disposition of our Class A Common Stock conducted through anon-U.S. office of anon-U.S. broker generally will not be subject to backup withholding or information reporting.
Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which theNon-U.S. Holder resides or is established.
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against aNon-U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.
Additional Withholding Tax on Payments Made to Foreign Accounts
Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or “FATCA”) on certain types of payments made tonon-U.S. financial institutions and certain othernon-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our Class A Common Stock 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 ornon-financial foreign entity is acting as an intermediary), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) thenon-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each direct and indirect substantial United States owner, or (3) the foreign financial institution ornon-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as IRSForm W-8BEN-E). If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States-owned foreign entities” (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments tonon-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.
Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our Class A Common Stock, and will apply to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2019.
Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our Class A Common Stock.
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The validity of the securities offered hereby will be passed upon for us by Haynes and Boone, LLP of Houston, Texas. Any underwriters or agents will be advised about other issues relating to the offering by counsel to be named in the applicable prospectus supplement.
The financial statements of Silver Run Acquisition Corporation II as of December 31, 2016 and for the period from November 16, 2016 (date of inception) through December 31, 2016, have been included herein and in the registration statement in reliance upon the reports of WithumSmith+Brown, PC, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
The consolidated financial statements of Alta Mesa Holdings, LP as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 included in this prospectus have been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report appearing herein.
The consolidated financial statements of Kingfisher Midstream, LLC as of December 31, 2016 and 2015, and for the year ended December 31, 2016 and the period from Inception (January 30, 2015) through December 31, 2015, have been included herein and in this registration statement in reliance upon the reports of EEPB, P.C., independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
Estimates of proved reserves included in this prospectus as of December 31, 2016 using SEC guidelines were prepared or derived from estimates prepared by the Corporate Planning and Reserves department of Alta Mesa Holdings, LP and were audited in a reserves audit by Ryder Scott, independent petroleum consultants. In addition, reserves estimates at December 31, 2016 using NYMEX pricing and Society of Petroleum Engineers-Petroleum Resource Management System guidelines were prepared or derived from estimates prepared by the Corporate Planning and Reserves department of Alta Mesa Holdings, LP and were audited in a reserves audit by Ryder Scott, independent petroleum consultants. These reserves estimates are included in this prospectus in reliance on the authority of such firm as experts in these matters. Ryder Scott did not audit thePV-10s prepared by the Corporate Planning and Reserves department of Alta Mesa Holdings, LP.
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WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement onForm S-1 under the Securities Act with respect to the shares of Class A Common Stock offered by this prospectus. This prospectus does not contain all of the information included in the registration statement. For further information pertaining to us and our Class A Common Stock you should refer to the registration statement and its exhibits. Statements contained in this prospectus concerning any of our contracts, agreements or other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed. Each statement in this prospectus relating to a contract or document filed as an exhibit is qualified in all respects by the filed exhibit.
We are subject to the informational requirements of the Exchange Act and file annual, quarterly and current reports and other information with the SEC. Our filings with the SEC are available to the public on the SEC’s website at http://www.sec.gov. Those filings are also available to the public on, or accessible through, our website under the heading “Investors” at www.altamesa.net. The information we file with the SEC or contained on or accessible through our corporate website or any other website that we may maintain is not part of this prospectus or the registration statement of which this prospectus is a part. You may also read and copy, at SEC prescribed rates, any document we file with the SEC, including the registration statement (and its exhibits) of which this prospectus is a part, at the SEC’s Public Reference Room located at 100 F Street, N.E., Washington D.C. 20549. You can call the SEC at1-800-SEC-0330 to obtain information on the operation of the Public Reference Room.
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Fin-97 | ||||
Fin-98 | ||||
Notes to Consolidated Financial Statements | Fin-99 | |||
Silver Run Acquisition Corporation II—Unaudited Pro Forma Financial Statements | ||||
Fin-103 |
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SILVER RUN ACQUISITION CORPORATION II
September 30, 2017 | December 31, 2016 | |||||||
(Unaudited) | (Audited) | |||||||
ASSETS: | ||||||||
Current assets: | ||||||||
Cash | $ | 546,322 | $ | 225,500 | ||||
Prepaid expenses | 122,427 | — | ||||||
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Total current assets | 668,749 | 225,500 | ||||||
Investment held in Trust Account | 1,038,946,417 | — | ||||||
Deferred offering costs | — | 169,552 | ||||||
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Total assets | $ | 1,039,615,166 | $ | 395,052 | ||||
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LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accrued expenses | $ | — | $ | 72,052 | ||||
Sponsor note | 1,500,000 | 300,000 | ||||||
Franchise taxes payable | 90,000 | — | ||||||
Income taxes payable | 1,349,746 | — | ||||||
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Total current liabilities | 2,939,746 | 372,052 | ||||||
Deferred underwriting discounts | 36,225,000 | — | ||||||
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Total liabilities | 39,164,746 | 372,052 | ||||||
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Class A common stock subject to possible redemption; 99,545,041 (at redemption value of approximately $10.00 per share) | 995,450,410 | — | ||||||
Stockholders’ equity: | ||||||||
Preferred shares, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding | — | — | ||||||
Class A common stock, $0.0001 par value, 400,000,000 shares authorized, 3,954,959 issued and outstanding (excluding 99,545,041shares subject to possible redemption) | 395 | — | ||||||
Class B common stock, $0.0001 par value, 50,000,000 shares authorized, 25,875,000 shares issued and outstanding | 2,588 | 2,588 | ||||||
Additionalpaid-in capital | 4,039,284 | 22,412 | ||||||
Retained earnings (accumulated deficit) | 957,743 | (2,000 | ) | |||||
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Total stockholders’ equity | 5,000,010 | 23,000 | ||||||
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Total liabilities and stockholders’ equity | $ | 1,039,615,166 | $ | 395,052 | ||||
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See accompanying notes to unaudited condensed financial statements.
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SILVER RUN ACQUISITION CORPORATION II
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | |||||||
Revenues | $ | — | $ | — | ||||
Operating expenses: | ||||||||
General and administrative expenses | 1,210,075 | 1,546,928 | ||||||
Franchise taxes | 45,000 | 90,000 | ||||||
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Total operating expenses | (1,255,075 | ) | (1,636,928 | ) | ||||
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Loss from operations | (1,255,075 | ) | (1,636,928 | ) | ||||
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Other income – investment income on Trust Account | 2,256,423 | 3,946,417 | ||||||
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Income before provision for income taxes | 1,001,348 | 2,309,489 | ||||||
Provision for income taxes | 773,998 | 1,349,746 | ||||||
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Net income attributable to common shares | $ | 227,350 | $ | 959,743 | ||||
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Weighted average number of shares outstanding: | ||||||||
Basic (excluding shares subject to possible redemption) | 29,829,959 | 28,577,517 | ||||||
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Diluted | 129,375,000 | 129,375,000 | ||||||
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Net income per share | ||||||||
Basic | $ | 0.01 | $ | 0.03 | ||||
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Diluted | $ | 0.00 | $ | 0.01 | ||||
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See accompanying notes to unaudited condensed financial statements.
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SILVER RUN ACQUISITION CORPORATION II
CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Nine Months Ended September 30, 2017
(Unaudited)
Class A Common Stock | Class B Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Stockholders’ Equity | ||||||||||||||||||||||||
Shares | Amount | Shares | Amount | |||||||||||||||||||||||||
Balances as of December 31, 2016 | — | $ | — | 25,875,000 | $ | 2,588 | $ | 22,412 | $ | (2,000 | ) | $ | 23,000 | |||||||||||||||
Sale of Class A Common Stock to Public | 103,500,000 | 10,350 | — | — | 1,034,989,650 | — | 1,035,000,000 | |||||||||||||||||||||
Underwriting discounts and offering expenses | — | — | — | — | (58,232,323 | ) | — | (58,232,323 | ) | |||||||||||||||||||
Sale of 15,133,333 Private Placement Warrants at $1.50 per warrant | — | — | — | — | 22,700,000 | — | 22,700,000 | |||||||||||||||||||||
Shares subject to possible redemption | (99,545,041 | ) | (9,955 | ) | — | — | (995,440,455 | ) | — | (995,450,410 | ) | |||||||||||||||||
Net income | — | — | — | — | — | 959,743 | 959,743 | |||||||||||||||||||||
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Balances as of September 30, 2017 | 3,954,959 | $ | 395 | 25,875,000 | $ | 2,588 | $ | 4,039,284 | $ | 957,743 | $ | 5,000,010 | ||||||||||||||||
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See accompanying notes to unaudited condensed financial statements.
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SILVER RUN ACQUISITION CORPORATION II
CONDENSED STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2017
(Unaudited)
Cash flows from operating activities: | ||||
Net income | $ | 959,743 | ||
Adjustments to reconcile net income to net cash used in operating activities: | ||||
Interest earned on investments held in Trust Account | (3,946,417 | ) | ||
Changes in operating assets and liabilities: | ||||
Prepaid expenses | (122,427 | ) | ||
Franchise taxes payable | 90,000 | |||
Income taxes payable | 1,349,746 | |||
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Net cash used in operating activities | (1,669,355 | ) | ||
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Cash flows from investing activities: | ||||
Cash deposited into Trust Account | (1,035,000,000 | ) | ||
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Net cash used in investing activities | (1,035,000,000 | ) | ||
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Cash flows from financing activities: | ||||
Proceeds from Public Offering | 1,035,000,000 | |||
Proceeds from sale of Private Placement Warrants | 22,700,000 | |||
Payment of underwriting discounts | (20,700,000 | ) | ||
Payment of offering costs | (1,209,823 | ) | ||
Payment of Sponsor note | (300,000 | ) | ||
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Net cash provided by financing activities | 1,036,990,177 | |||
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Net increase in cash | 320,822 | |||
Cash at beginning of period | 225,500 | |||
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Cash at end of period | $ | 546,322 | ||
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Supplemental disclosure ofnon-cash financing activities: | ||||
Deferred underwriting discounts | $ | 36,225,000 | ||
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See accompanying notes to unaudited condensed financial statements.
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SILVER RUN ACQUISITION CORPORATION II
NOTES TO CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. | Description of Organization and Business Operations |
Organization and General
Silver Run Acquisition Corporation II (the “Company”) was incorporated in Delaware on November 16, 2016. The Company was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (as amended, the “JOBS Act”). The Company’s sponsor is Silver Run Sponsor II, LLC; a Delaware limited liability company (the “Sponsor”).
As of September 30, 2017, the Company had not engaged in any significant operations. All activity for the period from November 16, 2016 (date of inception) through September 30, 2017 relates to the Company’s formation, the initial public offering (“Public Offering” as described below) and efforts directed towards locating and consummating a suitable initial Business Combination. The Company did not generate any operating revenues prior to September 30, 2017. The Company will generatenon-operating income in the form of interest income earned on cash and cash equivalents held in trust account. The Company has selected December 31st as its fiscal year end.
Financing
On March 24, 2017, the registration statement for the Public Offering was declared effective by the Securities and Exchange Commission (the “SEC”). On March 29, 2017 (the “IPO Closing Date”), the Company consummated the Public Offering of $1,035,000,000 in Units (as defined in Note 3), and the sale of $22,700,000 in warrants (the “Private Placement Warrants”) to the Sponsor (the “IPO Private Placement”). On the IPO Closing Date, the Company placed $1,035,000,000 of proceeds (including the Deferred Discount (as defined in Note 3)) from the Public Offering and the IPO Private Placement into a trust account at J.P. Morgan Chase Bank, N.A. (the “Trust Account”). The Company intends to finance the initial Business Combination from proceeds held in the Trust Account.
At the IPO Closing Date, the Company held $22,700,000 of proceeds from the Public Offering and the IPO Private Placement outside the Trust Account. Of these amounts, $20,700,000 was used to pay underwriting discounts in the Public Offering and $300,000 was used to repay a note payable to the Sponsor (see Note 4), with the balance reserved to pay accrued offering and formation costs, business, legal and accounting due diligence expenses on prospective acquisitions and continuing general and administrative expenses.
Trust Account
The proceeds held in the Trust Account are invested in money market funds that meet certain conditions under Rule2a-7 under the Investment Company Act of 1940, as amended and that invest only in direct U.S. government obligations. Funds will remain in the Trust Account until the earlier of (i) the consummation of the initial Business Combination or (ii) the distribution of the Trust Account proceeds as described below. The remaining proceeds outside the Trust Account may be used to pay for business, legal and accounting due diligence on prospective acquisitions and continuing general and administrative expenses.
The Company’s amended and restated certificate of incorporation provides that, other than the withdrawal of interest to pay taxes, if any, none of the funds held in the Trust Account will be released until the earlier of: (i) the completion of the initial Business Combination; (ii) the redemption of any shares of Class A common
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stock included in the Units (the “Public Shares”) sold in the Public Offering that have been properly tendered in connection with a stockholder vote to amend the Company’s amended and restated certificate of incorporation to modify the substance or timing of its obligation to redeem 100% of such shares of Class A common stock if it does not complete the initial Business Combination within 24 months from the closing of the Public Offering; and (iii) the redemption of 100% of the shares of Class A common stock included in the Units sold in the Public Offering if the Company is unable to complete an initial Business Combination within 24 months from the closing of the Public Offering (subject to the requirements of law). The proceeds deposited in the Trust Account could become subject to the claims of the Company’s creditors, if any, which could have priority over the claims of the Company’s public stockholders.
Business Combination
The Company’s management has broad discretion with respect to the specific application of the net proceeds of the Public Offering, although substantially all of the net proceeds of the Public Offering are intended to be generally applied toward consummating an initial Business Combination. The initial Business Combination must occur with one or more target businesses that together have an aggregate fair market value of at least 80% of the assets held in the Trust Account (excluding the deferred underwriting discounts and taxes payable on income earned on the Trust Account) at the time of the agreement to enter into the initial Business Combination. Furthermore, there is no assurance that the Company will be able to successfully effect an initial Business Combination.
The Company, after signing a definitive agreement for an initial Business Combination, will either (i) seek stockholder approval of the initial Business Combination at a meeting called for such purpose in connection with which public stockholders may seek to redeem their Public Shares, regardless of whether they vote for or against the initial Business Combination, for cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the initial Business Combination, including interest but less taxes payable, or (ii) provide stockholders with the opportunity to sell their Public Shares to the Company by means of a tender offer (and thereby avoid the need for a stockholder vote) for an amount in cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the initial Business Combination, including interest but less taxes payable. The decision as to whether the Company will seek stockholder approval of the initial Business Combination or will allow stockholders to sell their Public Shares in a tender offer will be made by the Company, solely in its discretion, and will be based on a variety of factors such as the timing of the transaction and whether the terms of the transaction would otherwise require the Company to seek stockholder approval, unless a vote is required by law or under NASDAQ rules. If the Company seeks stockholder approval, it will complete its initial Business Combination only if a majority of the outstanding shares of common stock voted are voted in favor of the initial Business Combination. However, in no event will the Company redeem its Public Shares in an amount that would cause its net tangible assets to be less than $5,000,001. In such case, the Company would not proceed with the redemption of its Public Shares and the related initial Business Combination, and instead may search for an alternate initial Business Combination.
If the Company holds a stockholder vote or there is a tender offer for Public Shares in connection with an initial Business Combination, a public stockholder will have the right to redeem its Public Shares for an amount in cash equal to its pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the initial Business Combination, including interest but less taxes payable. As a result, such shares of Class A Common Stock are recorded at redemption amount and classified as temporary equity upon the completion of the Public Offering, in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 480, “Distinguishing Liabilities from Equity.”
Pursuant to the Company’s amended and restated certificate of incorporation, if the Company is unable to complete the initial Business Combination within 24 months from the closing of the Public Offering, the Company will (i) cease all operations except for the purpose of winding up, (ii) as promptly as reasonably
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possible but no more than ten business days thereafter subject to lawfully available funds therefor, redeem the Public Shares, at aper-share price, payable in cash, equal to the aggregate amount then on deposit in the Trust Account including interest income but less taxes payable (less up to $100,000 of interest income to pay dissolution expenses), divided by the number of then outstanding Public Shares, which redemption will completely extinguish public stockholders’ rights as stockholders (including the right to receive further liquidating distributions, if any), subject to applicable law, and (iii) as promptly as reasonably possible following such redemption, subject to the approval of the Company’s remaining stockholders and the Company’s board of directors, dissolve and liquidate, subject in each case to the Company’s obligations under Delaware law to provide for claims of creditors and the requirements of other applicable law. The Sponsor and the Company’s officers and directors have entered into a letter agreement with the Company, pursuant to which they have agreed to waive their rights to liquidating distributions from the Trust Account with respect to any Founder Shares (as defined in Note 4) held by them if the Company fails to complete the initial Business Combination within 24 months of the closing of the Public Offering. However, if the Sponsor or any of the Company’s directors, officers or affiliates acquires Public Shares, they will be entitled to liquidating distributions from the Trust Account with respect to such shares if the Company fails to complete the initial Business Combination within the prescribed time period.
In the event of a liquidation, dissolution or winding up of the Company after an initial Business Combination, the Company’s stockholders are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the common stock. The Company’s stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the common stock, except that the Company will provide its public stockholders with the opportunity to redeem their Public Shares for cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account, upon the completion of the initial Business Combination and the other circumstances described above, subject to the limitations described herein.
2. | Summary of Significant Accounting Policies |
Basis of Presentation
The Company’s unaudited condensed interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and the rules and regulations of the SEC for interim financial information and the instructions to Form10-Q. Accordingly, the financial statements do not include all of the information and footnotes required by U.S. GAAP. In the opinion of management, all adjustments (consisting of normal accruals) considered for a fair presentation have been included. The Company has evaluated subsequent events after September 30, 2017. Operating results for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 or any other period. The accompanying unaudited condensed interim financial statements should be read in conjunction with the Company’s audited financial statements and notes thereto included in the Company’s prospectus filed with the SEC on March 22, 2017, as well as the Company’s Form8-K filed with the SEC on April 4, 2017. Management has determined that the Company has access to funds from the Sponsor entity that are sufficient to fund the working capital needs of the Company until the earlier of the consummation of the Business Combination or a minimum one year from the date of issuance of these financial statements.
Emerging Growth Company
Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply tonon-emerging growth companies but any such an election to opt out is irrevocable. The Company has elected not to
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opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of the Company’s financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.
Net Income Per Common Share
Net income per common share is computed by dividing net income applicable to common stockholders by the weighted average number of common shares outstanding during the period. An aggregate of 99,545,041 shares of Class A common stock subject to possible redemption at September 30, 2017 have been excluded from the calculation of basic income per common share since such shares, if redeemed, only participate in their pro rata share of the trust earnings. The Company has not considered the effect of the warrants sold in the Initial Public Offering (including the consummation of the over-allotment) and Private Placement Warrants to purchase 49,633,333 shares of the Company’s Class A common stock in the calculation of diluted income per share, since their inclusion would be anti-dilutive.
Cash and Cash Equivalents
The Company considers all short-term investments with an original maturity of three months or less when purchased to be cash equivalents.
Marketable Securities held in Trust Account
The amounts held in the Trust Account represent proceeds from the Public Offering and the IPO Private Placement of $1,035,000,000 which were invested in a money market instrument that invests in United States Treasury Securities with original maturities of six months or less and are classified as restricted assets because such amounts can only be used by the Company in connection with the consummation of an initial Business Combination.
As of September 30, 2017, marketable securities held in the Trust Account had a fair value of $1,038,946,417. At September 30, 2017, there was $3,946,417 of interest income held in the Trust Account available to be released to the Company to pay accrued tax expenses.
Redeemable Common Stock
As discussed in Note 1, all of the 103,500,000 Public Shares contain a redemption feature which allows for the redemption of Class A Common Stock under the Company’s liquidation or tender offer/stockholder approval provisions. In accordance with FASB ASC 480, redemption provisions not solely within the control of the Company require the security to be classified outside of permanent equity. Ordinary liquidation events, which involve the redemption and liquidation of all of the entity’s equity instruments, are excluded from the provisions of FASB ASC 480. Although the Company has not specified a maximum redemption threshold, its amended and restated certificate of incorporation provides that in no event will the Company redeem its Public Shares in an amount that would cause its net tangible assets to be less than $5,000,001.
The Company recognizes changes in redemption value immediately as they occur and will adjust the carrying value of the security to equal the redemption value at the end of each reporting period. Increases or decreases in the carrying amount of redeemable shares of Class A Common Stock shall be affected by charges against additional paid in capital.
Accordingly, at September 30, 2017, 99,545,041 of the 103,500,000 shares of Class A Common Stock included in the Units were classified outside of permanent equity at their redemption value.
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Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentration of credit risk consist of cash accounts in a financial institution which, at times, may exceed the Federal Depository Insurance Coverage of $250,000. The Company has not experienced losses on these accounts and management believes the Company is not exposed to significant risks on such accounts.
Financial Instruments
The fair value of the Company’s assets and liabilities, which qualify as financial instruments under FASB ASC 820, “Fair Value Measurements and Disclosures,” approximates the carrying amounts represented in the balance sheet.
Use of Estimates
The preparation of the financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Offering Costs
The Company complies with the requirements of FASB ASC340-10-S99-1 and SEC Staff Accounting Bulletin Topic 5A – “Expenses of Offering.” Offering costs of $58,232,323, consisting primarily of underwriting discounts of $56,925,000 (including $36,225,000 of which is deferred), and $1,307,323 of professional, filing, regulatory and other costs, were charged to additionalpaid-in capital.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes under FASB ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.
FASB ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. There were no unrecognized tax benefits as of September 30, 2017. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. No amounts were accrued for the payment of interest and penalties at September 30, 2017. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.
During the three and nine months ended September 30, 2017, the Company recorded federal income tax expense of $773,998 and $1,349,746, respectively, primarily related to interest income earned on the Trust Account. The Company’s effective tax rate for the three and nine months ended September 30, 2017, was 35% and 35%, respectively, which does not differ significantly from the U.S. federal statutory income tax rate of 35 percent.
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Related Parties
The Company follows subtopic ASC850-10 for the identification of related parties and disclosure of related party transactions.
Pursuant toSection 850-10-20, the related parties include: (a) affiliates of the Company (“Affiliate” means, with respect to any specified person, any other person that, directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with such person, as such terms are used in and construed under Rule 405 under the Securities Act); (b) entities for which investments in their equity securities would be required, absent the election of the fair value option under the Fair Value Option Subsection ofSection 825-10-15, to be accounted for by the equity method by the investing entity; (c) trusts for the benefit of employees, such as pension and profit-sharing trusts that are managed by or under the trusteeship of management; (d) principal owners of the Company; (e) management of the Company; (f) other parties with which the Company may deal if one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests; and (g) other parties that can significantly influence the management or operating policies of the transacting parties or that have an ownership interest in one of the transacting parties and can significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests.
Subsequent Events
The Company evaluates subsequent events and transactions that occur after the balance sheet date for potential recognition or disclosure. Any material events that occur between the balance sheet date and the date that the financial statements were issued are disclosed as subsequent events, while the financial statements are adjusted to reflect any conditions that existed at the balance sheet date.
Recent Accounting Pronouncements
The Company’s management does not believe that any recently issued, but not yet effective, accounting pronouncements, if currently adopted, would have an effect on the Company’s financial statements.
3. | Public Offering |
On the IPO Closing Date, the Company sold 103,500,000 units (the “Units”) at a price of $10.00 per Unit, generating gross proceeds to the Company of $1,035,000,000. Each Unit consists of one share of Class A Common Stock andone-third of one warrant (each whole warrant, a “Warrant” and, collectively, the “Warrants”). Each whole Warrant entitles the holder thereof to purchase one whole share of Class A Common Stock at a price of $11.50 per share. No fractional shares will be issued upon separation of the Units and only whole Warrants will trade. Each Warrant will become exercisable on the later of 30 days after the completion of the initial Business Combination or 12 months from the closing of the Public Offering and will expire five years after the completion of the initial Business Combination or earlier upon redemption or liquidation. Once the Warrants become exercisable, the Company may redeem the outstanding Warrants in whole and not in part at a price of $0.01 per Warrant upon a minimum of 30 days’ prior written notice of redemption, if and only if the last sale price of the Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a30-trading day period ending on the third trading day prior to the date on which the Company sent the notice of redemption to the Warrant holders.
The Company paid an upfront underwriting discount of 2.0% ($20,700,000) of the per Unit offering price to the underwriters at the closing of the Public Offering, with an additional fee (the “Deferred Discount”) of 3.5% ($36,225,000) of the gross offering proceeds payable upon the Company’s completion of an initial Business Combination. The Deferred Discount will become payable to the underwriters from the amounts held in the Trust Account solely in the event the Company completes an initial Business Combination.
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4. | Related Party Transactions |
Founder Shares
On November 21, 2016, the Sponsor purchased 11,500,000 shares (the “Founder Shares”) of Class B common stock, par value $0.0001 per share (the “Class B Common Stock”), for an aggregate purchase price of $25,000, or approximately $0.002 per share. In March 2017, the Sponsor transferred 33,000 Founder Shares to each of the Company’s independent directors (together with the Sponsor, the “Initial Stockholders”) at their original purchase price. In March 2017, the Company effected stock dividends of approximately 1.25 shares for each outstanding share of Class B Common Stock, resulting in the Initial Stockholders holding an aggregate of 25,875,000 Founder Shares. As used herein, unless the context otherwise requires, “Founder Shares” shall be deemed to include the shares of Class A Common Stock issuable upon conversion thereof. The Founder Shares are identical to the Class A Common Stock included in the Units sold in the Public Offering except that the Founder Shares automatically convert into shares of Class A Common Stock at the time of the initial Business Combination and are subject to certain transfer restrictions, as described in more detail below. Holders of Founder Shares may also elect to convert their shares of Class B Common Stock into an equal number of shares of Class A Common Stock, subject to adjustment, at any time.
The Company’s Initial Stockholders have agreed, subject to limited exceptions, not to transfer, assign or sell any of their Founder Shares until the earlier to occur of: (A) one year after the completion of the initial Business Combination or (B) subsequent to the initial Business Combination, (x) if the last sale price of the Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30 trading day period commencing at least 150 days after the initial Business Combination, or (y) the date on which the Company completes a liquidation, merger, stock exchange or other similar transaction that results in all of the Company’s stockholders having the right to exchange their shares of common stock for cash, securities or other property.
Private Placement Warrants
The Sponsor purchased an aggregate of 15,133,333 Private Placement Warrants at a price of $1.50 per whole warrant ($22,700,000 in the aggregate) in a private placement that occurred simultaneously with the closing of the Public Offering. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was added to the proceeds from the Public Offering held in the Trust Account such that at the closing of the Public Offering $1,035,000,000 was placed in the Trust Account. If the initial Business Combination is not completed within 24 months from the closing of the Public Offering, the proceeds from the sale of the Private Placement Warrants held in the Trust Account will be used to fund the redemption of the Public Shares (subject to the requirements of applicable law) and the Private Placement Warrants will expire worthless. The Private Placement Warrants arenon-redeemable and exercisable on a cashless basis so long as they are held by the Sponsor or its permitted transferees.
The Sponsor and the Company’s officers and directors have agreed, subject to limited exceptions, not to transfer, assign or sell any of their Private Placement Warrants until 30 days after the completion of the initial Business Combination.
In March 2017, the Sponsor transferred 33,000 Founder Shares to each of our independent director nominees at their original purchase price.
Registration Rights
The holders of Founder Shares, Private Placement Warrants and warrants that may be issued upon conversion of working capital loans, if any, are entitled to registration rights (in the case of the Founder Shares, only after conversion of such shares to shares of Class A Common Stock) as stated in the registration rights
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agreement signed on the date of the prospectus for the Public Offering. These holders are entitled to certain demand and “piggyback” registration rights.
However, the registration rights agreement provides that the Company will not permit any registration statement filed under the Securities Act to become effective until termination of the applicablelock-up period for the securities to be registered. The Company will bear the expenses incurred in connection with the filing of any such registration statements.
Related Party Loans
On November 22, 2016, the Sponsor agreed to loan the Company an aggregate of up to $300,000 to cover expenses related to the Public Offering pursuant to a promissory note (the “2016 Note”). This loan isnon-interest bearing and payable on the earlier of March 31, 2017 or the completion of the Public Offering. On November 22, 2016, the Company borrowed $300,000 under the 2016 Note. On March 29, 2017, the full $300,000 balance of the 2016 Note was repaid to the Sponsor.
On September 27, 2017, the Sponsor agreed to loan the Company an aggregate of up to $2,000,000 to cover expenses related to the business combination pursuant to a promissory note (the ‘‘2017 Note’’). This loan is non-interest bearing and payable on the earlier of March 29, 2019 or the date on which the Company consummates a business combination. On September 27, 2017, the Company borrowed $1,500,000 under the 2017 Note. At the time of this filing, $1,500,000 remains outstanding on the 2017 Note.
Administrative Support Agreement
The Company has agreed to pay an affiliate of the Sponsor a total of $10,000 per month for office space, utilities and secretarial and administrative support. Upon completion of the initial Business Combination or the Company’s liquidation, the Company will cease paying these monthly fees.
Forward Purchase Agreement
In March 2017, the Company entered into a forward purchase agreement (“Forward Purchase Agreement”) pursuant to which Riverstone VI SRII Holdings, L.P. (“Fund VI Holdings”) agreed to purchase an aggregate of up to 40,000,000 shares of the Company’s Class A common stock, plus an aggregate of up to 13,333,333 warrants (“Forward Purchase Warrant”), for an aggregate purchase price of up to $400,000,000 or $10.00 per unit (collectively, “Forward Purchase Units”). Each Forward Purchase Warrant has the same terms as each of the Private Placement Warrants.
The obligations under the Forward Purchase Agreement do not depend on whether any public stockholders elect to redeem their shares in connection with the initial Business Combination and provide the Company with a minimum funding level for the initial Business Combination. Additionally, the obligations of Fund VI Holdings to purchase the Forward Purchase Units are subject to termination prior to the closing of the sale of such units by mutual written consent of the Company and such party, or automatically: (i) if the proposed offering is not consummated on or prior to June 30, 2017; (ii) if the initial Business Combination is not consummated within 24 months from the closing of the proposed offering, unless extended up to a maximum of sixty (60) days in accordance with the amended and restated certificate of incorporation; or (iii) if the Sponsor or the Company become subject to any voluntary or involuntary petition under the United States federal bankruptcy laws or any state insolvency law, in each case which is not withdrawn within sixty (60) days after being filed, or a receiver, fiscal agent or similar officer is appointed by a court for business or property of the Sponsor or the Company in each case which is not removed, withdrawn or terminated within sixty (60) days after such appointment. In addition, the obligations of Fund VI Holdings to purchase the Forward Purchase Units are subject to fulfillment of customary closing conditions, including that the initial Business Combination must be consummated substantially concurrently with the purchase of the Forward Purchase Units.
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Riverstone Contribution Agreement and Business Combination Forward Purchase Agreement
See Note 8 for a description of the contribution agreement entered into between the Company and Riverstone VI Alta Mesa Holdings, L.P. on August 16, 2017 and the related forward purchase agreement entered into between the Company and Fund VI Holdings
5. | Deferred Underwriting Discounts |
The Company is committed to pay the Deferred Discount of 3.5% of the gross proceeds of the Public Offering, or $36,225,000, to the underwriters upon the Company’s completion of an initial Business Combination (as discussed in Note 3). The underwriters are not entitled to receive any of the interest earned on Trust Account funds that would be used to pay the Deferred Discount, and no Deferred Discount is payable to the underwriters if an initial Business Combination is not completed within 24 months after the Public Offering.
6. | Stockholders’ Equity |
Common Stock
The authorized common stock of the Company includes up to 400,000,000 shares of Class A Common Stock and 50,000,000 shares of Class B Common Stock. If the Company enters into an initial Business Combination, it may (depending on the terms of such an initial Business Combination) be required to increase the number of shares of Class A Common Stock which the Company is authorized to issue at the same time as the Company’s stockholders vote on the initial Business Combination to the extent the Company seeks stockholder approval in connection with the initial Business Combination. Holders of the Company’s common stock are entitled to one vote for each share of common stock. At September 30, 2017, there were 103,500,000 shares of Class A Common Stock, of which 99,545,041 were classified outside of permanent equity, and 25,875,000 shares of Class B Common Stock issued and outstanding.
Preferred Stock
The Company is authorized to issue 1,000,000 shares of preferred stock with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors. At September 30, 2017 there were no shares of preferred stock issued or outstanding.
Warrants
Public warrants may only be exercised for a whole number of shares. No fractional shares will be issued upon exercise of the public warrants. The public warrants will become exercisable on the later of (a) 30 days after the completion of a Business Combination or (b) 12 months from the closing of the Initial Public Offering; provided in each case that the Company has an effective registration statement under the Securities Act covering the shares of Class A common stock issuable upon exercise of the warrants and a current prospectus relating to them is available (or we permit holders to exercise their warrants on a cashless basis under the circumstances specified in the warrant agreement). We are not registering the shares of Class A common stock issuable upon exercise of the warrants at this time. However, we have agreed that as soon as practicable, but in no event later than 15 business days after the closing of our initial business combination, we will use our best efforts to file and have an effective registration statement covering the shares of Class A common stock issuable upon exercise of the warrants, to maintain a current prospectus relating to those shares of Class A common stock until the warrants expire or are redeemed; provided, that if our Class A common stock is at the time of any exercise of a warrant not listed on a national securities exchange such that it satisfies the definition of a “covered security” under Section 18(b)(1) of the Securities Act, we may, at our option, require holders of public warrants who exercise their warrants to do so on a ‘‘cashless basis’’ in accordance with Section 3(a)(9) of the Securities Act and, in the event we so elect, we will not be required to file or maintain in effect a registration statement, but we will be required to use our best efforts to register or qualify the shares under applicable blue sky laws to the
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extent an exemption is not available. The Public Warrants will expire five years after the completion of a Business Combination or earlier upon redemption or liquidation.
The Private Placement Warrants are identical to the public warrants underlying the Units sold in the Initial Public Offering, except that the Private Placement Warrants and the common stock issuable upon the exercise of the Private Placement Warrants will not be transferable, assignable or salable until 30 days after the completion of a Business Combination, subject to certain limited exceptions.
7. | Trust Account and Fair Value Measurements |
On the IPO Closing Date, gross proceeds of $1,035,000,000 and $22,700,000 from the Public Offering and the IPO Private Placement, respectively, less underwriting discounts of $20,700,000 and $2,000,000 designated to fund the Company’s accrued formation and offering costs (including the note payable to the Sponsor), business, legal and accounting due diligence expenses on prospective acquisitions, and continuing general and administrative expenses, were placed in the Trust Account.
As of September 30, 2017, marketable securities held in the Trust Account had a fair value of $1,038,946,417 which was invested in a money market instrument that invests in United States Treasury Securities with original maturities of six months or less.
The following table presents information about the Company’s assets that are measured on a recurring basis as of September 30, 2017 and indicates the fair value hierarchy of the valuation techniques that the Company utilized to determine such fair value. In general, fair values determined by Level 1 inputs utilize quoted prices (unadjusted) in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs utilize data points that are observable, such as quoted prices, interest rates and yield curves. Fair values determined by Level 3 inputs are unobservable data points for the asset or liability, and includes situations where there is little, if any, market activity for the asset or liability.
Description | September 30, 2017 | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | ||||||||||||
Investments held in Trust Account | $ | 1,038,946,417 | $ | 1,038,946,417 | $ | — | $ | — |
8. | Contribution and Forward Purchase Agreements |
Contribution Agreements
On August 16, 2017, the Company entered into:
• | the Contribution Agreement dated as of August 16, 2017 (as the same may be amended from time to time, the “Alta Mesa Contribution Agreement”), among High Mesa Holdings, LP, a Delaware limited partnership (the “Alta Mesa Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the Alta Mesa Contributor, Alta Mesa Holdings, LP, a Texas limited partnership (“Alta Mesa”), Alta Mesa Holdings GP, LLC, a Texas limited liability company and sole general partner of Alta Mesa (“Alta Mesa GP”), and, solely for certain provisions therein, the equity owners of the Alta Mesa Contributor, pursuant to which the Company will acquire from the Alta Mesa Contributor (a) all of the limited partner interests in Alta Mesa held by the Alta Mesa Contributor and (b) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP; |
• | the Contribution Agreement, dated as of August 16, 2017 (as the same may be amended from time to time, the “Kingfisher Contribution Agreement”), among KFM Holdco, LLC, a Delaware limited liability company (the “Kingfisher Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the Kingfisher Contributor, pursuant to which the Company will acquire 100% of the outstanding membership interests in Kingfisher; and |
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• | the Contribution Agreement, dated as of August 16, 2017 (as the same may be amended from time to time, the “Riverstone Contribution Agreement” and, together with the Alta Mesa Contribution Agreement and the Kingfisher Contribution Agreement, the “Contribution Agreements”), between Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”), pursuant to which the Company will acquire from the Riverstone Contributor all of the limited partner interests in Alta Mesa held by the Riverstone Contributor. |
Pursuant to the Contribution Agreements, the Company will contribute cash to SRII Opco, LP, a Delaware limited partnership and wholly owned subsidiary of the Company (“SRII Opco”), in exchange for (a) a number of common units representing limited partner interests in SRII Opco (the “SRII Opco Common Units”) equal to the number of shares of the Company’s Class A common stock, outstanding as of the closing (the “Closing”) of the transactions contemplated by the Contribution Agreements (the “Transactions”), and (b) a number of SRII Opco warrants exercisable for SRII Opco Common Units equal to the number of the Company’s warrants outstanding as of the Closing. Following the Closing, the Company will control SRII Opco through its ownership of SRII Opco GP, LLC, the sole general partner of SRII Opco.
Pursuant to the terms of the Alta Mesa Contribution Agreement, at the Closing, the Alta Mesa Contributor will receive consideration consisting of 220,000,000 SRII Opco Common Units, as adjusted (i) upward for any inorganic acquisition capital expenditures invested by Alta Mesa during the interim period (based on a value of $10.00 per SRII Opco Common Unit), (ii) downward for the Riverstone Contributor’s $200 million contribution to Alta Mesa, which was made in connection with the parties entering into the Contribution Agreements (based on a value of $10.00 per SRII Opco Common Unit), and (iii) downward for debt and transaction expenses (based on a value of $10.00 per SRII Opco Common Unit). The Alta Mesa Contributor will also purchase from the Company a number of shares of a new class of common stock designated as the Class C common stock equal to the number of SRII Opco Common Units received by the Alta Mesa Contributor at the Closing.
In addition to the above, for a period of seven years following the Closing, the Alta Mesa Contributor will be entitled to receive an aggregate of up to $800 million in earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A common stock equals or exceeds certain prices (each such payment, an “Earn-Out Payment”). The earn-out consideration will be paid in the form of SRII Opco Common Units (and the Alta Mesa Contributor will acquire a corresponding number of shares of Class C common stock) as follows based on the specified 20-Day VWAP hurdle: $14.00 – 10,714,285 SRII Opco Common Units; $16.00 – 9,375,000 SRII Opco Common Units; $18.00 – 13,888,889 SRII Opco Common Units and $20.00 – 12,500,000 SRII Opco Common Units.
The Alta Mesa Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the Alta Mesa Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the Alta Mesa Contributor will be entitled to receive each such Earn-Out Payment. The Alta Mesa Contributor will be entitled to the earn-out consideration in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of its assets, if the consideration paid to holders of Class A common stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.
The Company will also contribute $400 million in cash to Alta Mesa at the Closing.
Pursuant to the Kingfisher Contribution Agreement, at the Closing, the Kingfisher Contributor will receive consideration consisting of:
• | 55,000,000 SRII Opco Common Units; and |
• | subject to the Kingfisher Contributor’s election to receive additional SRII Opco Common Units as described below, $800 million in cash, as adjusted for net working capital, debt, transaction expenses, capital expenditures and banking fees. |
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The Kingfisher Contributor will also purchase from the Company a number of shares of Class C common stock equal to the number of SRII Opco Common Units received by the Kingfisher Contributor at the Closing.
If the Company does not have cash on hand at the Closing necessary to pay the cash consideration to the Kingfisher Contributor, the Kingfisher Contributor has the option to receive any deficit in the form of SRII Opco Common Units (and acquire a corresponding number of shares of Class C common stock) valued at $10.00 per SRII Opco Common Unit. At the Closing, $5 million of the cash consideration to be received by the Kingfisher Contributor will be funded into escrow to satisfy any post-Closing purchase price adjustments. If such escrowed amount is insufficient to satisfy any post-Closing adjustment, then the Kingfisher Contributor will transfer to the Company a number of SRII Opco Common Units (not to exceed 16,000,000 SRII Opco Common Units), and a corresponding number of shares of Class C common stock, with a value equal to the deficiency.
In addition to the above, for a period of seven years following the Closing, the Kingfisher Contributor will be entitled to receive an aggregate of up to $200 million in earn-out consideration if the 20-Day VWAP of the Class A Common Stock equals or exceeds certain prices. The earn-out consideration will be paid in the form of SRII Opco Common Units (and the Kingfisher Contributor will acquire a corresponding number of shares of Class C common stock) as follows based on the specified 20-Day VWAP hurdle: $14.00 – 7,142,857 SRII Opco Common Units and $16.00 – 6,250,000 SRII Opco Common Units.
The terms of the payment of the earn-out consideration, including in connection with a liquidity event of the Company, are substantially similar to the terms of the payment of the earn-out consideration to the Alta Mesa Contributor described above.
Pursuant to the Riverstone Contribution Agreement, the Riverstone Contributor will receive 20,000,000 SRII Opco Common Units in exchange for the Riverstone Contributor’s limited partner interests in Alta Mesa and will acquire an equal number of shares of Class C common stock from the Company.
The Contribution Agreements contain customary representations, warranties and covenants and may be terminated by the parties thereto as set forth therein, including if the Transactions are not consummated by February 28, 2018. The Transactions will constitute a “Business Combination” under the Company’s amended and restated certificate of incorporation.
Business Combination Forward Purchase Agreement
In connection with the execution of the Contribution Agreements, on August 16, 2017, the Company entered into a forward purchase agreement (the “Business Combination Forward Purchase Agreement”) with Fund VI Holdings, pursuant to which the Company has agreed to sell at the Closing, and Fund VI Holdings has agreed to purchase, up to $200 million of shares of Class A common stock at a purchase price of $10.00 per share. The number of shares of Class A common stock to be sold by the Company, and purchased by Fund VI Holdings, will equal that number which, after payment of the aggregate purchase price paid by Fund VI Holdings under the Business Combination Forward Purchase Agreement, will result in gross proceeds to the Company in an aggregate amount necessary to satisfy any exercise of rights of the public stockholders in connection with the Transactions or determined by the Company and Fund VI Holdings to be necessary for general corporate purposes in connection with or following consummation of the Transactions, but in no event will the number of shares of Class A common stock purchased exceed 20,000,000 shares.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Silver Run Acquisition Corporation II
We have audited the accompanying balance sheet of Silver Run Acquisition Corporation II (the “Company”), as of December 31, 2016, and the related statements of operations, changes in stockholder’s equity and cash flows for the period from November 16, 2016 (date of inception) to December 31, 2016. 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 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 financial statements are free of material misstatement. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Silver Run Acquisition Corporation II as of December 31, 2016, and the results of its operations and its cash flows for the period from November 16, 2016 (date of inception) to December 31, 2016, in accordance with accounting principles generally accepted in the United States of America.
/s/ WithumSmith+Brown, PC
New York, New York
March 22, 2017
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Silver Run Acquisition Corporation II
December 31, 2016
ASSETS: | ||||
Current assets – cash | $ | 225,500 | ||
Deferred offering costs | 169,552 | |||
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Total assets | $ | 395,052 | ||
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LIABILITIES AND STOCKHOLDER’S EQUITY | ||||
Current Liabilities: | ||||
Accrued formation and offering costs | $ | 72,052 | ||
Sponsor note | 300,000 | |||
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Total current liabilities | 372,052 | |||
Commitments and contingencies | ||||
Stockholder’s equity: | ||||
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding | — | |||
Class A common stock, $0.0001 par value; 400,000,000 shares authorized; none issued and outstanding | — | |||
Class B common stock, $0.0001 par value; 50,000,000 shares authorized; 25,875,000 shares issued and outstanding (1) | 2,588 | |||
Additionalpaid-in capital | 22,412 | |||
Accumulated deficit | (2,000 | ) | ||
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Total stockholder’s equity | 23,000 | |||
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Total liabilities and stockholder’s equity | $ | 395,052 | ||
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(1) | Share amounts have been retroactively restated to reflect the stock dividends of 14,375,000 shares in March 2017 (see Note 6). |
See accompanying notes to financial statements
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Silver Run Acquisition Corporation II
For the period from November 16, 2016 (date of inception) to December 31, 2016
Revenue | $ | — | ||
General and administrative expenses | 2,000 | |||
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Net loss attributable to common stock | $ | (2,000 | ) | |
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Weighted average number of shares outstanding: | ||||
Basic and diluted (1) | 25,875,000 | |||
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Net loss per common share: | ||||
Basic and diluted | $ | (0.00 | ) | |
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(1) | Share amounts have been retroactively restated to reflect the stock dividends of 14,375,000 shares in March 2017 (see Note 6). |
See accompanying notes to financial statements
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Silver Run Acquisition Corporation II
STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
For the period from November 16, 2016 (date of inception) to December 31, 2016
Class B Common Stock | Additional Paid-in Capital | Accumulated Deficit | Stockholder’s Equity | |||||||||||||||||
Shares | Amount | |||||||||||||||||||
Sale of common stock to Sponsor at approx. $0.001 per share (1) | 25,875,000 | $ | 2,588 | $ | 22,412 | $ | — | $ | 25,000 | |||||||||||
Net loss | — | — | — | (2,000 | ) | (2,000 | ) | |||||||||||||
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Balances, December 31, 2016 | 25,875,000 | $ | 2,588 | $ | 22,412 | $ | (2,000 | ) | $ | 23,000 | ||||||||||
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(1) | Share amounts have been retroactively restated to reflect the stock dividends of 14,375,000 shares in March 2017 (see Note 6). |
See accompanying notes to financial statements
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Silver Run Acquisition Corporation II
For the period from November 16, 2016 (date of inception) to December 31, 2016
Net loss | $ | (2,000 | ) | |
Adjustments to reconcile net loss to net cash used in operations: | ||||
Increase in accounts payable and accrued liabilities | 2,000 | |||
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Net cash used in operating activities | — | |||
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Cash flows from financing activities: | ||||
Proceeds from Sponsor note | 300,000 | |||
Payment of offering costs | (74,500 | ) | ||
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Net cash provided by financing activities | 225,500 | |||
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Increase in cash | 225,500 | |||
Cash at beginning of period | — | |||
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Cash at end of period | $ | 225,500 | ||
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Supplemental disclosure ofnon-cash financing activities | ||||
Deferred offering costs included in accrued formation and offering costs | $ | 70,052 | ||
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Offering costs paid by Sponsor in exchange for Founder Shares | $ | 25,000 | ||
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See accompanying notes to financial statements
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Note 1 – Description of Organization and Business Operations
Organization and General
Silver Run Acquisition Corporation II (the “Company”) was incorporated in Delaware on November 16, 2016. The Company was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Initial Business Combination”). The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended, or the “Securities Act,” as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”).
At December 31, 2016, the Company had not commenced any operations. All activity for the period from November 16, 2016 (inception) through December 31, 2016 relates to the Company’s formation and the proposed initial public offering (“Proposed Offering”) described below. The Company will not generate any operating revenues until after completion of its Initial Business Combination, at the earliest. The Company will generatenon-operating income in the form of interest income on cash and cash equivalents from the proceeds derived from the Proposed Offering. The Company has selected December 31st as its fiscal year end.
Sponsor and Proposed Financing
The Company’s sponsor is Silver Run Sponsor II, LLC, a Delaware limited liability company (the “Sponsor”). The Company intends to finance its Initial Business Combination with proceeds from the proposed $900,000,000 initial public offering of Units (as defined below) (Note 3) and a $20,000,000 private placement (Note 4). Upon the closing of the Proposed Offering and the private placement, $900,000,000 (or $1,035,000,000 if the underwriters’ over-allotment option is exercised in full – Note 3) will be held in a trust account (the “Trust Account”) (discussed below).
The Trust Account
The proceeds held in the Trust Account will be invested only in U.S. government treasury bills with a maturity of one hundred eighty (180) days or less or in money market funds that meet certain conditions under Rule2a-7 under the Investment Company Act of 1940 and that invest only in direct U.S. government obligations. Funds will remain in the Trust Account until the earlier of (i) the consummation of the Initial Business Combination or (ii) the distribution of the Trust Account proceeds as described below. The remaining proceeds outside the Trust Account may be used to pay for business, legal and accounting due diligence on prospective acquisitions and continuing general and administrative expenses.
The Company’s amended and restated certificate of incorporation will provide that, other than the withdrawal of interest to pay taxes, if any, none of the funds held in the Trust Account will be released until the earlier of: (i) the completion of the Initial Business Combination; (ii) the redemption of any shares of Class A common stock included in the Units (the “Public Shares”) being sold in the Proposed Offering that have been properly tendered in connection with a stockholder vote to amend the Company’s amended and restated certificate of incorporation to modify the substance or timing of its obligation to redeem 100% of such shares of Class A common stock if it does not complete the Initial Business Combination within 24 months from the closing of the Proposed Offering; and (iii) the redemption of 100% of the shares of Class A common stock included in the Units being sold in the Proposed Offering if the Company is unable to complete an Initial Business Combination within 24 months from the closing of the Proposed Offering (subject to the requirements of law). The proceeds deposited in the Trust Account could become subject to the claims of the Company’s creditors, if any, which could have priority over the claims of the Company’s public stockholders.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 – Description of Organization and Business Operations (Continued)
Initial Business Combination
The Company’s management has broad discretion with respect to the specific application of the net proceeds of the Proposed Offering, although substantially all of the net proceeds of the Proposed Offering are intended to be generally applied toward consummating an Initial Business Combination. The Initial Business Combination must occur with one or more target businesses that together have an aggregate fair market value of at least 80% of the assets held in the Trust Account (excluding the deferred underwriting commissions and taxes payable on income earned on the Trust Account) at the time of the agreement to enter into the Initial Business Combination. Furthermore, there is no assurance that the Company will be able to successfully effect an Initial Business Combination.
The Company, after signing a definitive agreement for an Initial Business Combination, will either (i) seek stockholder approval of the Initial Business Combination at a meeting called for such purpose in connection with which stockholders may seek to redeem their shares, regardless of whether they vote for or against the Initial Business Combination, for cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the Initial Business Combination, including interest but less taxes payable, or (ii) provide stockholders with the opportunity to sell their Public Shares to the Company by means of a tender offer (and thereby avoid the need for a stockholder vote) for an amount in cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the Initial Business Combination, including interest but less taxes payable. The decision as to whether the Company will seek stockholder approval of the Initial Business Combination or will allow stockholders to sell their Public Shares in a tender offer will be made by the Company, solely in its discretion, and will be based on a variety of factors such as the timing of the transaction and whether the terms of the transaction would otherwise require the Company to seek stockholder approval, unless a vote is required by law or under NASDAQ rules. If the Company seeks stockholder approval, it will complete its Initial Business Combination only if a majority of the outstanding shares of common stock voted are voted in favor of the Initial Business Combination. However, in no event will the Company redeem its Public Shares in an amount that would cause its net tangible assets to be less than $5,000,001. In such case, the Company would not proceed with the redemption of its Public Shares and the related Initial Business Combination, and instead may search for an alternate Initial Business Combination.
If the Company holds a stockholder vote or there is a tender offer for shares in connection with an Initial Business Combination, a public stockholder will have the right to redeem its shares for an amount in cash equal to its pro rata share of the aggregate amount then on deposit in the Trust Account as of two business days prior to the consummation of the Initial Business Combination, including interest but less taxes payable. As a result, such shares of Class A common stock will be recorded at redemption amount and classified as temporary equity upon the completion of the Proposed Offering, in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 480, “Distinguishing Liabilities from Equity.”
Pursuant to the Company’s amended and restated certificate of incorporation, if the Company is unable to complete the Initial Business Combination within 24 months from the closing of the Proposed Offering, the Company will (i) cease all operations except for the purpose of winding up, (ii) as promptly as reasonably possible but no more than ten business days thereafter subject to lawfully available funds therefor, redeem the Public Shares, at aper-share price, payable in cash, equal to the aggregate amount then on deposit in the Trust Account including interest earned on the funds held in the Trust Account and not previously released to us to pay the Company’s franchise and income taxes (less up to $100,000 of interest to pay dissolution expenses), divided by the number of then outstanding Public Shares, which redemption will completely extinguish public stockholder’s rights as stockholders (including the right to receive further liquidating distributions, if any), subject to applicable law, and (iii) as promptly as reasonably possible following such redemption, subject to the
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 – Description of Organization and Business Operations (Continued)
approval of the Company’s remaining stockholders and the Company’s board of directors, dissolve and liquidate, subject in each case to the Company’s obligations under Delaware law to provide for claims of creditors and the requirements of other applicable law. The Sponsor and the Company’s officers and directors will enter into a letter agreement with the Company, pursuant to which they will agree to waive their rights to liquidating distributions from the Trust Account with respect to any Founder Shares (as defined below) held by them if the Company fails to complete the Initial Business Combination within 24 months of the closing of the Proposed Offering. However, if the Sponsor or any of the Company’s directors, officers or affiliates acquires shares of Class A common stock in or after the Proposed Offering, they will be entitled to liquidating distributions from the Trust Account with respect to such shares if the Company fails to complete the Initial Business Combination within the prescribed time period.
In the event of a liquidation, dissolution or winding up of the Company after an Initial Business Combination, the Company’s stockholders are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the common stock. The Company’s stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the common stock, except that the Company will provide its stockholders with the opportunity to redeem their Public Shares for cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account, upon the completion of the Initial Business Combination, subject to the limitations described herein.
Note 2 – Summary of Significant Accounting Policies
Basis of Presentation
The financial statements of the Company are presented in U.S. dollars in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In connection with the Company’s assessment of going concern considerations in accordance with ASU2014-15, “Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern”, as of December 31, 2016, the Company does not have sufficient liquidity to meet its current obligations. However, management has determined that the Company has access to funds from the Sponsor entity that are sufficient to fund the working capital needs of the Company until the earlier of the consummation of the Proposed Offering or a minimum one year from the date of issuance of these financial statements.
Emerging Growth Company
Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply tonon-emerging growth companies but any such an election to opt out is irrevocable. The Company has elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of the Company’s financial statement with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 2 – Summary of Significant Accounting Policies (Continued)
Net Loss Per Common Share
Net loss per common share is computed by dividing net loss applicable to common stockholders by the weighted average number of common shares outstanding during the period, plus, to the extent dilutive, the incremental number of shares of common stock to settle warrants, as calculated using the treasury stock method. At December 31, 2016, the Company did not have any dilutive securities and other contracts that could, potentially, be exercised or converted into common stock and then share in the earnings of the Company under the treasury stock method. As a result, diluted loss per common share is the same as basic loss per common share for the period.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash accounts in a financial institution, which, at times, may exceed the Federal Depository Insurance Coverage of $250,000. The Company has not experienced losses on these accounts and management believes the Company is not exposed to significant risks on such accounts.
Financial Instruments
The fair value of the Company’s assets and liabilities, which qualify as financial instruments under the FASB ASC 820, “Fair Value Measurements and Disclosures,” approximates the carrying amounts represented in the balance sheet.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Deferred Offering Costs
The Company complies with the requirements of the FASB ASC340-10-S99-1 and SEC Staff Accounting Bulletin Topic 5A – “Expenses of Offering.” Deferred offering costs of approximately $170,000 consist of costs incurred in connection with formation and preparation for the Proposed Offering. These costs, together with the underwriter discount, will be charged to additionalpaid-in capital upon completion of the Proposed Offering or charged to operations if the Proposed Offering is not completed.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes under FASB ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 2 – Summary of Significant Accounting Policies (Continued)
FASB ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. There were no unrecognized tax benefits as of December 31, 2016. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. No amounts were accrued for the payment of interest and penalties at December 31, 2016. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.
Recent Accounting Pronouncements
In August 2014, FASB issued ASU2014-15, “Presentation of Financial Statements – Going Concern” (Subtopic205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. ASU2014-15 provides guidance on management’s responsibility to evaluate whether there is a substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The amendments in ASU2014-15 are effective for annual reporting periods ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company has adopted the methodologies prescribed by ASU2014-15 and it did not have a material effect on its financial position or results of operations. SeeBasis of Presentation for additional considerations.
Management does not believe that any other recently issued, but not yet effective, accounting pronouncements, if currently adopted, would have an effect on the Company’s financial statements.
Note 3 – Public Offering
Pursuant to the Proposed Offering, the Company intends to offer for sale up to 90,000,000 units at a price of $10.00 per unit (the “Units”). The Sponsor has committed to purchase an aggregate of 13,333,333 warrants at a price of $1.50 per warrant in a private placement that will close simultaneously with the Proposed Offering.
Each Unit consists of one share of the Company’s Class A common stock, $0.0001 par value, andone-third of one warrant (each, a “Warrant” and, collectively, the “Warrants”). Each whole Warrant entitles the holder to purchase one share of Class A common stock at a price of $11.50 per share. No fractional shares will be issued upon separation of the Units and only whole Warrants will trade. Each Warrant will become exercisable on the later of 30 days after the completion of the Company’s Initial Business Combination or 12 months from the closing of the Proposed Offering and will expire five years after the completion of the Company’s Initial Business Combination or earlier upon redemption or liquidation. Once the Warrants become exercisable, the Company may redeem the outstanding Warrants in whole and not in part at a price of $0.01 per Warrant upon a minimum of 30 days’ prior written notice of redemption, if and only if the last sale price of the Company’s Class A common stock equals or exceeds $18.00 per share for any 20 trading days within a30-trading day period ending on the third trading day prior to the date on which the Company sent the notice of redemption to the Warrant holders.
The Company expects to grant the underwriters a45-day option to purchase up to 13,500,000 additional Units to cover any over-allotments at the initial public offering price less the underwriting discounts and commissions. The Units that would be issued in connection with the over-allotment option would be identical to the Units issued in the Proposed Offering.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 3 – Public Offering (Continued)
The Company expects to pay an underwriting discount of 2.0% of the per Unit offering price to the underwriters at the closing of the Proposed Offering, with an additional fee (the “Deferred Discount”) of 3.5% of the gross offering proceeds payable upon the Company’s completion of an Initial Business Combination. The Deferred Discount will become payable to the underwriters from the amounts held in the Trust Account solely in the event the Company completes its Initial Business Combination.
Note 4 – Related Party Transactions
Founder Shares
On November 21, 2016, the Sponsor purchased 11,500,000 shares of Class B common stock (the “Founder Shares”) for an aggregate price of $25,000, or approximately $0.002 per share. As used herein, unless the context otherwise requires, “Founder Shares” shall be deemed to include the shares of Class A common stock issuable upon conversion thereof. The Founder Shares are identical to the Class A common stock included in the Units being sold in the Proposed Offering except that the Founder Shares automatically convert into shares of Class A common stock at the time of the Company’s Initial Business Combination and are subject to certain transfer restrictions, as described in more detail below. Holders of Founder Shares may also elect to convert their shares of Class B common stock into an equal number of shares of Class A common stock, subject to adjustment as provided above, at any time. The Sponsor has agreed to forfeit up to 1,500,000 Founder Shares to the extent that the over-allotment option is not exercised in full by the underwriters (see Note 6). The forfeiture will be adjusted to the extent that the over-allotment option is not exercised in full by the underwriters so that the Founder Shares will represent 20.0% of the Company’s issued and outstanding shares after the Proposed Offering. If the Company increases or decreases the size of the offering, the Company will effect a stock dividend or share contribution back to capital, as applicable, immediately prior to the consummation of the Proposed Offering in such amount as to maintain the Founder Share ownership of the Company’s stockholders prior to the Proposed Offering at 20.0% of the Company’s issued and outstanding common stock upon the consummation of the Proposed Offering.
The Company’s initial stockholders will agree, subject to limited exceptions, not to transfer, assign or sell any of their Founder Shares until the earlier to occur of: (A) one year after the completion of the Initial Business Combination or (B) subsequent to the Initial Business Combination, (x) if the last sale price of the Company’s Class A common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any30-trading day period commencing at least 150 days after the Initial Business Combination, or (y) the date on which we complete a liquidation, merger, stock exchange or other similar transaction that results in all of the Company’s stockholders having the right to exchange their shares of common stock for cash, securities or other property.
The Sponsor will agree to purchase an aggregate of 13,333,333 private placement warrants (or 15,133,333 if the over-allotment option is exercised in full) at a price of $1.50 per whole warrant (approximately $20,000,000 in the aggregate or $22,700,000 in the aggregate if the over-allotment option is exercised in full) in a private placement that will occur simultaneously with the closing of the Proposed Offering (the “Private Placement Warrants”). Each whole Private Placement Warrant is exercisable for one whole share of the Company’s Class A common stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants will be added to the proceeds from the Proposed Offering to be held in the Trust Account such that at the closing of the Proposed Offering $900.0 million (or $1,035.0 million if the underwriters exercise their over-allotment option in full) will be held in the Trust Account. If the Initial Business Combination is not completed within 24 months from the closing of the Proposed Offering, the proceeds from the sale of the Private Placement Warrants held in the Trust Account will be used to fund the redemption of the Public Shares (subject to the requirements of applicable law) and the Private Placement Warrants will expire worthless. The Private Placement
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 4 – Related Party Transactions (Continued)
Warrants will benon-redeemable and exercisable on a cashless basis so long as they are held by the Sponsor or its permitted transferees.
The Sponsor and the Company’s officers and directors will agree, subject to limited exceptions, not to transfer, assign or sell any of their Private Placement Warrants until 30 days after the completion of the Initial Business Combination.
Registration Rights
The holders of Founder Shares, Private Placement Warrants and Warrants that may be issued upon conversion of working capital loans, if any, will be entitled to registration rights (in the case of the Founder Shares, only after conversion of such shares to shares of Class A common stock) pursuant to a registration rights agreement to be signed on or before the date of the prospectus for the Proposed Offering. These holders will be entitled to certain demand and “piggyback” registration rights. However, the registration rights agreement provides that the Company will not permit any registration statement filed under the Securities Act to become effective until termination of the applicablelock-up period for the securities to be registered. The Company will bear the expenses incurred in connection with the filing of any such registration statements.
Related Party Loans
On November 22, 2016, the Sponsor loaned the Company an aggregate of $300,000 to cover expenses related to the Proposed Offering pursuant to a promissory note (the “Note”). This loan isnon-interest bearing and payable on the earlier of March 31, 2017 or the completion of the Proposed Offering. As of March 20, 2017, $300,000 is still outstanding under the Note.
Administrative Support Agreement
Commencing on the date the Units are first listed on the NASDAQ, the Company has agreed to pay the Sponsor a total of $10,000 per month for office space, utilities and secretarial and administrative support. Upon completion of the Initial Business Combination or the Company’s liquidation, the Company will cease paying these monthly fees.
Note 5 – Stockholder’s Equity
Common Stock
The authorized common stock of the Company includes up to 400,000,000 shares of Class A common stock and 50,000,000 shares of Class B common stock (see Note 6). If the Company enters into an Initial Business Combination, it may (depending on the terms of such an Initial Business Combination) be required to increase the number of shares of Class A common stock which the Company is authorized to issue at the same time as the Company’s stockholders vote on the Initial Business Combination to the extent the Company seeks stockholder approval in connection with the Initial Business Combination. Holders of the Company’s common stock are entitled to one vote for each share of common stock. At December 31, 2016, there were 25,875,000 shares of Class B common stock issued and outstanding (see Note 6).
Preferred Stock
The Company is authorized to issue 1,000,000 shares of preferred stock with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors (see Note 6). At December 31, 2016, there were no shares of preferred stock issued or outstanding.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Note 6 – Subsequent Events
In March 2017, the Company effected stock dividends in the aggregate of approximately 1.25 shares for each outstanding share of Class B common stock, resulting in the initial stockholders holding an aggregate of 25,875,000 Founder Shares. The stock dividends also adjusted the shares subject to forfeiture from 1,500,000 to 3,375,000, to the extent that the over-allotment option is not exercised in full by the underwriters so that the Founder Shares will represent 20.0% of the Company’s issued and outstanding shares after the Proposed Offering.
In March 2017, the Company entered into a forward purchase agreement (“Forward Purchase Agreement”) pursuant to which Riverstone VI SRII Holdings, L.P. (“Fund VI Holdings”) agreed to purchase an aggregate of up to 40,000,000 shares of the Company’s Class A common stock, plus an aggregate of up to 13,333,333 warrants (“Forward Purchase Warrant”), for an aggregate purchase price of up to $400,000,000 or $10.00 per unit (collectively, “Forward Purchase Units”). Each Forward Purchase Warrant has the same terms as each of the Private Placement Warrants.
The obligations under the Forward Purchase Agreement do not depend on whether any public stockholders elect to redeem their shares in connection with the Initial Business Combination and provide the Company with a minimum funding level for the Initial Business Combination. Additionally, the obligations of Fund VI Holdings to purchase the Forward Purchase Units are subject to termination prior to the closing of the sale of such units by mutual written consent of the Company and such party, or automatically: (i) if the Proposed Offering is not consummated on or prior to June 30, 2017; (ii) if the Initial Business Combination is not consummated within 24 months from the closing of the Proposed Offering, unless extended up to a maximum of sixty (60) days in accordance with the amended and restated certificate of incorporation; or (iii) if the Sponsor or the Company become subject to any voluntary or involuntary petition under the United States federal bankruptcy laws or any state insolvency law, in each case which is not withdrawn within sixty (60) days after being filed, or a receiver, fiscal agent or similar officer is appointed by a court for business or property of the Sponsor or the Company in each case which is not removed, withdrawn or terminated within sixty (60) days after such appointment. In addition, the obligations of Fund VI Holdings to purchase the Forward Purchase Units are subject to fulfillment of customary closing conditions, including that the Initial Business Combination must be consummated substantially concurrently with the purchase of the Forward Purchase Units.
In March 2017, the Company updated the articles of incorporation to increase the authorized capital stock. The total number of all shares of all classes of capital stock is 451,000,000, consisting of (a) 450,000,000 shares of common stock including (i) 400,000,000 shares of Class A common stock and (ii) 50,000,000 shares of Class B common stock, and (b) 1,000,000 shares of preferred stock.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 3,740 | $ | 7,185 | ||||
Short-term restricted cash | 1,173 | 433 | ||||||
Accounts receivable, net of allowance of $802 and $889, respectively | 71,260 | 37,611 | ||||||
Other receivables | 679 | 8,061 | ||||||
Receivables due from affiliate | 839 | 8,883 | ||||||
Prepaid expenses and other current assets | 2,215 | 3,986 | ||||||
Derivative financial instruments | 6,952 | 83 | ||||||
|
|
|
| |||||
Total current assets | 86,858 | 66,242 | ||||||
|
|
|
| |||||
PROPERTY AND EQUIPMENT | ||||||||
Oil and natural gas properties, successful efforts method, net | 944,867 | 712,162 | ||||||
Other property and equipment, net | 9,139 | 9,731 | ||||||
|
|
|
| |||||
Total property and equipment, net | 954,006 | 721,893 | ||||||
|
|
|
| |||||
OTHER ASSETS | ||||||||
Investment in LLC – cost | 9,000 | 9,000 | ||||||
Deferred financing costs, net | 1,943 | 3,029 | ||||||
Notes receivable due from affiliate | 12,121 | 9,987 | ||||||
Deposits and other long-term assets | 14,686 | 2,977 | ||||||
Derivative financial instruments | 5,282 | 723 | ||||||
|
|
|
| |||||
Total other assets | 43,032 | 25,716 | ||||||
|
|
|
| |||||
TOTAL ASSETS | $ | 1,083,896 | $ | 813,851 | ||||
|
|
|
| |||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable and accrued liabilities | $ | 144,546 | $ | 79,710 | ||||
Advances fromnon-operators | 3,872 | 4,058 | ||||||
Advances from related party | 47,794 | 42,528 | ||||||
Asset retirement obligations | 3,960 | 4,900 | ||||||
Derivative financial instruments | 348 | 21,207 | ||||||
|
|
|
| |||||
Total current liabilities | 200,520 | 152,403 | ||||||
|
|
|
| |||||
LONG-TERM LIABILITIES | ||||||||
Asset retirement obligations, net of current portion | 65,152 | 61,128 | ||||||
Long-term debt, net | 565,247 | 529,905 | ||||||
Notes payable to founder | 27,861 | 26,957 | ||||||
Derivative financial instruments | — | 4,482 | ||||||
Other long-term liabilities | 7,613 | 6,870 | ||||||
|
|
|
| |||||
Total long-term liabilities | 665,873 | 629,342 | ||||||
|
|
|
| |||||
TOTAL LIABILITIES | 866,393 | 781,745 | ||||||
Commitments and Contingencies (Note 11) | ||||||||
PARTNERS’ CAPITAL | 217,503 | 32,106 | ||||||
|
|
|
| |||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL | $ | 1,083,896 | $ | 813,851 | ||||
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended September 30, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
OPERATING REVENUES AND OTHER | ||||||||
Oil | $ | 169,611 | $ | 115,778 | ||||
Natural gas | 37,780 | 20,277 | ||||||
Natural gas liquids | 22,814 | 10,109 | ||||||
Other revenues | 274 | 358 | ||||||
|
|
|
| |||||
Total operating revenues | 230,479 | 146,522 | ||||||
|
|
|
| |||||
Gain on sale of assets | — | 3,723 | ||||||
Gain on acquisition of oil and natural gas properties | 6,893 | — | ||||||
Gain (loss) on derivative contracts | 38,024 | (23,970 | ) | |||||
|
|
|
| |||||
Total operating revenues and other | 275,396 | 126,275 | ||||||
|
|
|
| |||||
OPERATING EXPENSES | ||||||||
Lease and plant operating expense | 49,836 | 45,222 | ||||||
Marketing and transportation expense | 21,566 | 8,140 | ||||||
Production and ad valorem taxes | 8,812 | 8,021 | ||||||
Workover expense | 5,112 | 3,242 | ||||||
Exploration expense | 19,930 | 15,304 | ||||||
Depreciation, depletion, and amortization expense | 80,082 | 66,857 | ||||||
Impairment expense | 29,206 | 14,238 | ||||||
Accretion expense | 1,447 | 1,615 | ||||||
General and administrative expense | 35,534 | 32,909 | ||||||
|
|
|
| |||||
Total operating expenses | 251,525 | 195,548 | ||||||
|
|
|
| |||||
INCOME (LOSS) FROM OPERATIONS | 23,871 | (69,273 | ) | |||||
OTHER INCOME (EXPENSE) | ||||||||
Interest expense | (39,069 | ) | (52,253 | ) | ||||
Interest income | 880 | 672 | ||||||
|
|
|
| |||||
Total other income (expense) | (38,189 | ) | (51,581 | ) | ||||
|
|
|
| |||||
LOSS BEFORE STATE INCOME TAXES | (14,318 | ) | (120,854 | ) | ||||
Provision for state income taxes | 285 | 107 | ||||||
|
|
|
| |||||
NET LOSS | $ | (14,603 | ) | $ | (120,961 | ) | ||
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net loss | $ | (14,603 | ) | $ | (120,961 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depreciation, depletion, and amortization expense | 80,082 | 66,857 | ||||||
Impairment expense | 29,206 | 14,238 | ||||||
Accretion expense | 1,447 | 1,615 | ||||||
Amortization of deferred financing costs | 2,205 | 3,004 | ||||||
Amortization of debt discount | — | 382 | ||||||
Dry hole expense | 2,447 | 423 | ||||||
Expired leases | 8,394 | 6,689 | ||||||
(Gain) loss on derivative contracts | (38,024 | ) | 23,970 | |||||
Settlements of derivative contracts | 1,775 | 83,839 | ||||||
Premium paid on derivative contracts | (520 | ) | — | |||||
Interest converted into debt | 904 | 904 | ||||||
Interest on notes receivable due from affiliates | (619 | ) | (574 | ) | ||||
Gain on sale of assets | — | (3,723 | ) | |||||
Gain on acquisition of oil and natural gas properties | (6,893 | ) | — | |||||
Changes in assets and liabilities: | ||||||||
Restricted cash | (740 | ) | (92,046 | ) | ||||
Accounts receivable | (33,649 | ) | (4,774 | ) | ||||
Other receivables | 7,382 | 14,436 | ||||||
Receivables due from affiliate | 169 | 214 | ||||||
Prepaid expenses and othernon-current assets | (9,938 | ) | (1,898 | ) | ||||
Advances from related party | 5,266 | 13,425 | ||||||
Settlement of asset retirement obligation | (6,083 | ) | (1,465 | ) | ||||
Accounts payable, accrued liabilities, and other liabilities | 27,308 | 2,918 | ||||||
|
|
|
| |||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | 55,516 | 7,473 | ||||||
|
|
|
| |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Capital expenditures for property and equipment | (244,308 | ) | (149,179 | ) | ||||
Acquisitions | (55,236 | ) | — | |||||
Proceeds from sale of property | — | 1,405 | ||||||
Notes receivable due from affiliate | (1,515 | ) | — | |||||
|
|
|
| |||||
NET CASH USED IN INVESTING ACTIVITIES | (301,059 | ) | (147,774 | ) | ||||
|
|
|
| |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from long-term debt | 286,065 | 141,935 | ||||||
Repayments of long-term debt | (251,622 | ) | (1,500 | ) | ||||
Additions to deferred financing costs | (220 | ) | (799 | ) | ||||
Capital contributions | 207,875 | — | ||||||
|
|
|
| |||||
NET CASH PROVIDED BY FINANCING ACTIVITIES | 242,098 | 139,636 | ||||||
|
|
|
| |||||
NET DECREASE IN CASH AND CASH EQUIVALENTS | (3,445 | ) | (665 | ) | ||||
CASH AND CASH EQUIVALENTS, beginning of period | 7,185 | 8,869 | ||||||
|
|
|
| |||||
CASH AND CASH EQUIVALENTS, end of period | $ | 3,740 | $ | 8,204 | ||||
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. DESCRIPTION OF BUSINESS
Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin commonly referred to as the STACK. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. Our operations also include othernon-STACK oil and natural gas interests within the continental United States.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form10-K for the year ended December 31, 2016 (the “2016 Annual Report”). As of September 30, 2017, our significant accounting policies are consistent with those discussed in Note 2 in the 2016 Annual Report.
Principles of Consolidation and Reporting
The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2016, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2016 Annual Report.
The condensed consolidated financial statements included herein as of September 30, 2017, and for the nine months ended September 30, 2017 and 2016, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form10-Q and Article 10 of RegulationS-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.
Use of Estimates
The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, state taxes, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.
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Accounts Receivable
Accounts receivable consists of the following:
September 30, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Oil, natural gas and natural gas liquids sales | $ | 27,670 | $ | 25,156 | ||||
Joint interest billings | 16,792 | 10,427 | ||||||
Pooling interest (1) | 27,600 | 2,917 | ||||||
Allowance for doubtful accounts | (802 | ) | (889 | ) | ||||
|
|
|
| |||||
Total accounts receivable, net | $ | 71,260 | $ | 37,611 | ||||
|
|
|
|
(1) | Pooling interest relates to Oklahoma’s forced pooling process to ensure all working interest owners participate in drilling and spacing units for wells we propose to drill as operator on our STACK acreage. We expect full realization from our pooling efforts associated with the drilling activities in Oklahoma totaling approximately $27.6 million over the next 12 months. |
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that do not elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. We plan to adopt the standard during the fourth quarter of 2018 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.
We are in the process of assessing our contracts and evaluating the impact on the condensed consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements. We will complete our evaluation during the fourth quarter of 2017.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)(“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will
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be effective for interim and annual periods beginning after December 15, 2018, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.
At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have a material impact on our condensed consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date. We plan to adopt ASU 2016-02 on January 1, 2019.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our condensed consolidated statements of cash flows.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU2016-18”), which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for interim and annual periods after December 15, 2017, and should be applied prospectively. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
3. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow disclosures andnon-cash investing and financing activities are presented below:
Nine Months Ended September 30, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Supplemental cash flow information: | ||||||||
Cash paid for interest | $ | 25,675 | $ | 37,006 | ||||
Cash paid for state income taxes | — | 422 | ||||||
Non-cash investing and financing activities: | ||||||||
Change in asset retirement obligations | 3,778 | 1,032 | ||||||
Asset retirement obligations assumed, purchased properties | 705 | — | ||||||
Change in accruals or liabilities for capital expenditures | 41,322 | 11,524 |
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4. ACQUISITIONS
2017 Acquisitions
In July 2017,we closed on our acquisition to acquire certain oil and natural gas properties in Oklahoma with an unaffiliated third party for a purchase price of approximately $45.4 million, net of customary post-closing adjustments. The acquired oil and natural gas properties were primarily unproved leasehold. We accounted for this transaction as an asset acquisition with substantially all of the purchase price allocated to unproved property within oil and natural gas properties, successful efforts method, net. We funded the acquisition with borrowings under our senior secured revolving credit facility.
In September 2017, we acquired approximately $4.6 million of unproved leasehold in Oklahoma. We funded the transaction with cash on hand and accounted for this transaction as an asset acquisition.
In September 2017, we completed a transaction to acquire certain proved oil and natural gas properties from Brown & Borelli, et al (the “B&B Acquisition”) for a purchase price of approximately $3.5 million, net of customary post-closing purchase price adjustments. We funded the acquisition with cash on hand. The acquisition was accounted for using the acquisition method under ASC 805, “Business Combinations,” which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date. The difference between the historical results of operations and the unaudited pro forma results of operations for the three and nine months ended September 30, 2017 and 2016 was determined to be de minimus and therefore pro forma information has not been provided.
A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the B&B Acquisition based on the preliminary fair value at the acquisition date is as follows:
(in thousands) | ||||
Summary of Consideration | ||||
Cash | $ | 3,469 | ||
|
| |||
Total consideration paid | 3,469 | |||
|
| |||
Summary of Purchase Price Allocation | ||||
Plus: fair value of liabilities assumed | ||||
Asset retirement obligations assumed | 370 | |||
|
| |||
Total fair value liabilities assumed | 370 | |||
|
| |||
Less: fair value of assets acquired | ||||
Proved oil and natural gas properties | 9,106 | |||
|
| |||
Total fair value assets acquired | 9,106 | |||
|
| |||
Bargain purchase gain | $ | (5,267 | ) | |
|
|
The fair value of the net assets acquired was approximately $9.1 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $5.3 million. The acquisition resulted in a bargain purchase gain primarily as a result of timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increased proved reserves. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statements of operations.
In April 2017, we completed an acquisition of certainnon-STACK proved oil and natural gas properties from Setanta Energy, LLC (the “Setanta” Acquisition) for a purchase price of approximately $0.9 million, net of customary post-closing purchase price adjustments. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest. The acquisition was accounted for using the acquisition method under ASC 805.
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A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the Setanta Acquisition based on the preliminary fair value at the acquisition date is as follows:
(in thousands) | ||||
Summary of Consideration | ||||
Cash | $ | 890 | ||
|
| |||
Total consideration paid | 890 | |||
|
| |||
Summary of Purchase Price Allocation | ||||
Plus: fair value of liabilities assumed | ||||
Asset retirement obligations assumed | 89 | |||
|
| |||
Total fair value liabilities assumed | 89 | |||
|
| |||
Less: fair value of assets acquired | ||||
Proved oil and natural gas properties | 2,605 | |||
Unproved oil and natural gas properties | — | |||
|
| |||
Total fair value assets acquired | 2,605 | |||
|
| |||
Bargain Purchase Gain | $ | (1,626 | ) | |
|
|
The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.6 million. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statement of operations.
In accordance with ASC 805, the following unaudited pro forma results of operations for the nine months ended September 30, 2017 and 2016 have been prepared to give effect to the Setanta acquisition on our condensed consolidated results of operations as if it had occurred on January 1, 2016. Therefore, the bargain purchase gain on acquisition of $1.6 million has been included in pro forma income (loss) for the nine months ended September 30, 2016. The difference between the historical results of operations and the unaudited pro forma results of operations for the three months ended September 30, 2017 and 2016 was determined to be de minimus and therefore not provided.
Total Operating Revenues | Income (Loss) | |||||||
(in thousands) | ||||||||
Pro forma results of operations for the nine months ended September 30, 2017 | $ | 230,819 | $ | (16,188 | ) | |||
Pro forma results of operations for the nine months ended September 30, 2016 | $ | 146,664 | $ | (119,455 | ) |
2016 Acquisition
On December 31, 2016, High Mesa, Inc. (“High Mesa”) purchased fromBCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. We accounted for the Contributed Wells as a business combination in the prior year and the results of operations from the acquisition is reflected in the consolidated statement of operations for the three and nine months ended September 30, 2016 as presented below as if it had occurred on January 1, 2016.
Total Operating Revenues | Income (Loss) | |||||||
(in thousands) | ||||||||
Pro forma results of operations for the three months ended September 30, 2016 | $ | 64,370 | $ | (19,143 | ) | |||
Pro forma results of operations for the nine months ended September 30, 2016 | $ | 157,898 | $ | (112,822 | ) |
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The unaudited pro forma information has been derived from historical information and are for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during this period.
The fair value of the oil and natural gas properties are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity price and estimates by management at the time of the valuation are the most sensitive and may be subject to change.
5. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
September 30, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
OIL AND NATURAL GAS PROPERTIES | ||||||||
Unproved properties | $ | 136,410 | $ | 116,311 | ||||
Accumulated impairment of unproved properties | (18,974 | ) | (65 | ) | ||||
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Unproved properties, net | 117,436 | 116,246 | ||||||
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Proved oil and natural gas properties | 1,931,207 | 1,611,249 | ||||||
Accumulated depreciation, depletion, amortization and impairment | (1,103,776 | ) | (1,015,333 | ) | ||||
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Proved oil and natural gas properties, net | 827,431 | 595,916 | ||||||
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TOTAL OIL AND NATURAL GAS PROPERTIES, net | 944,867 | 712,162 | ||||||
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OTHER PROPERTY AND EQUIPMENT | ||||||||
Land | 5,339 | 4,730 | ||||||
Office furniture and equipment, vehicles | 20,170 | 19,446 | ||||||
Accumulated depreciation | (16,370 | ) | (14,445 | ) | ||||
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OTHER PROPERTY AND EQUIPMENT, net | 9,139 | 9,731 | ||||||
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TOTAL PROPERTY AND EQUIPMENT, net | $ | 954,006 | $ | 721,893 | ||||
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6. FAIR VALUE DISCLOSURES
The Company follows ASC 820, “Fair Value Measurements and Disclosures.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.
The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no
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quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.
Our senior notes are carried at historical cost, and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $545.0 million at September 30, 2017. This estimation is based on the most recent trading values of the senior notes at or near the reporting dates, which is a Level 1 determination. See Note 9 for information on long-term debt.
We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.
Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and natural gas properties with a carrying amount of $36.2 million were written down to their fair value of $7.0 million, resulting in an impairment charge of $29.2 million for the nine months ended September 30, 2017. For the nine months ended September 30, 2016, oil and natural gas properties with a carrying amount of $28.7 million were written down to their fair value of $14.5 million, resulting in an impairment charge of $14.2 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $1.2 million and $1.0 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2017 and 2016, respectively.
The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(in thousands) | ||||||||||||||||
At September 30, 2017: | ||||||||||||||||
Financial Assets: | ||||||||||||||||
Commodity derivative contracts | — | $ | 24,558 | — | $ | 24,558 | ||||||||||
Financial Liabilities: | ||||||||||||||||
Commodity derivative contracts | — | $ | 12,672 | — | $ | 12,672 | ||||||||||
At December 31, 2016: | ||||||||||||||||
Financial Assets: | ||||||||||||||||
Commodity derivative contracts | — | $ | 15,773 | — | $ | 15,773 | ||||||||||
Financial Liabilities: | ||||||||||||||||
Commodity derivative contracts | — | $ | 40,656 | — | $ | 40,656 |
The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 7.
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7. DERIVATIVE FINANCIAL INSTRUMENTS
We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 9, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes.
From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.
We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we usemark-to-market accounting, recognizing changes in the fair value of derivative contracts in the condensed consolidated statements of operations at each reporting date.
Derivative contracts are subject to master netting arrangements and are presented on a net basis in the condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed consolidated balance sheets. Likewise, derivative liabilities could be presented in a derivative asset account.
The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:
Fair Values of Derivative Contracts:
September 30, 2017 | ||||||||||||
Balance sheet location | Gross Fair Value of Assets | Gross amounts offset against assets in the Balance Sheet | Net Fair Value of Assets presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 13,904 | $ | (6,952 | ) | $ | 6,952 | |||||
Derivative financial instruments, long-term assets | 10,654 | (5,372 | ) | 5,282 | ||||||||
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Total | $ | 24,558 | $ | (12,324 | ) | $ | 12,234 | |||||
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Balance sheet location | Gross Fair Value of Liabilities | Gross amounts offset against liabilities in the Balance Sheet | Net Fair Value of Liabilities presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 7,300 | $ | (6,952 | ) | $ | 348 | |||||
Derivative financial instruments, long-term liabilities | 5,372 | (5,372 | ) | — | ||||||||
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Total | $ | 12,672 | $ | (12,324 | ) | $ | 348 | |||||
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December 31, 2016 | ||||||||||||
Balance sheet location | Gross Fair Value of Assets | Gross amounts offset against assets in the Balance Sheet | Net Fair Value of Assets presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 3,296 | $ | (3,213 | ) | $ | 83 | |||||
Derivative financial instruments, long-term assets | 12,477 | (11,754 | ) | 723 | ||||||||
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Total | $ | 15,773 | $ | (14,967 | ) | $ | 806 | |||||
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Balance sheet location | Gross Fair Value of Liabilities | Gross amounts offset against liabilities in the Balance Sheet | Net Fair Value of Liabilities presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 24,420 | $ | (3,213 | ) | $ | 21,207 | |||||
Derivative financial instruments, long-term liabilities | 16,236 | (11,754 | ) | 4,482 | ||||||||
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Total | $ | 40,656 | $ | (14,967 | ) | $ | 25,689 | |||||
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The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations:
Derivatives not designated as hedging instruments under ASC 815 | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(in thousands) | ||||||||||||||||
Gain (loss) on derivative contracts | ||||||||||||||||
Oil commodity contracts | $ | (10,873 | ) | $ | 577 | $ | 31,665 | $ | (22,794 | ) | ||||||
Natural gas commodity contracts | 1,035 | 3,265 | 6,763 | (506 | ) | |||||||||||
Natural gas liquids commodity contracts | (630 | ) | (334 | ) | (404 | ) | (670 | ) | ||||||||
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Total gain (loss) on derivative contracts | $ | (10,468 | ) | $ | 3,508 | $ | 38,024 | $ | (23,970 | ) | ||||||
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Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, toset-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility.
If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.
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We had the following open derivative contracts for crude oil at September 30, 2017:
OIL DERIVATIVE CONTRACTS
Volume in Bbls | Weighted Average | Range | ||||||||||||||
Period and Type of Contract | High | Low | ||||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | 643,500 | $ | 51.16 | $ | 57.25 | $ | 46.00 | |||||||||
Collar Contracts | ||||||||||||||||
Long Call Options | 46,000 | 85.00 | 85.00 | 85.00 | ||||||||||||
Short Call Options | 437,000 | 60.51 | 85.00 | 54.40 | ||||||||||||
Long Put Options | 391,000 | 48.24 | 50.00 | 47.00 | ||||||||||||
Short Put Options | 299,000 | 36.38 | 37.00 | 35.00 | ||||||||||||
2018 | ||||||||||||||||
Price Swap Contracts | 1,825,000 | 52.74 | 57.25 | 50.27 | ||||||||||||
Collar Contracts | ||||||||||||||||
Long Call Options | 365,000 | 54.00 | 54.00 | 54.00 | ||||||||||||
Short Call Options | 2,190,000 | 60.87 | 62.00 | 60.50 | ||||||||||||
Long Put Options | 1,825,000 | 50.00 | 50.00 | 50.00 | ||||||||||||
Short Put Options | 2,190,000 | 40.26 | 42.00 | 40.00 | ||||||||||||
2019 | ||||||||||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 1,606,000 | 61.44 | 63.00 | 56.50 | ||||||||||||
Long Put Options | 1,606,000 | 50.00 | 50.00 | 50.00 | ||||||||||||
Short Put Options | 1,606,000 | 38.07 | 40.00 | 37.50 |
We had the following open derivative contracts for natural gas at September 30, 2017:
NATURAL GAS DERIVATIVE CONTRACTS
Volume in | Weighted | Range | ||||||||||||||
Period and Type of Contract | MMBtu | Average | High | Low | ||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | 232,500 | $ | 3.40 | $ | 3.40 | $ | 3.39 | |||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 3,036,000 | 3.69 | 4.11 | 3.25 | ||||||||||||
Long Put Options | 2,728,500 | 3.17 | 3.60 | 3.00 | ||||||||||||
Long Call Options | 155,000 | 2.95 | 2.95 | 2.95 | ||||||||||||
Short Put Options | 2,883,500 | 2.60 | 3.00 | 2.50 | ||||||||||||
2018 | ||||||||||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 6,582,000 | 5.26 | 5.53 | 4.00 | ||||||||||||
Long Put Options | 5,925,000 | 4.43 | 4.50 | 3.60 | ||||||||||||
Short Put Options | 5,925,000 | 3.92 | 4.00 | 3.00 |
In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX or Brent ICE indices or may reflect a mix of positions settling on various of these benchmarks.
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We had the following open derivative contracts for natural gas liquids at September 30, 2017:
NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS
Volume in Gal | Weighted Average | Range | ||||||||||||||
Period and Type of Contract | High | Low | ||||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | ||||||||||||||||
Short Price Swaps | 1,545,600 | $ | 0.47 | $ | 0.47 | $ | 0.47 |
We had the following open financial basis swaps at September 30, 2017:
BASIS SWAP DERIVATIVE CONTRACTS
Volume in MMBtu (1) | Reference Price 1 | Reference Price 2 | Period | Weighted Average Spread ($ per MMBtu) | ||||||||
2,915,000 | TEX/OKL Mainline (PEPL) | NYMEX Henry Hub | Oct’17 – Dec’ 17 | $ | (0.21 | ) | ||||||
6,980,000 | TEX/OKL Mainline (PEPL) | NYMEX Henry Hub | Jan’18 – Dec’ 18 | (0.30 | ) | |||||||
152,500 | WAHA | NYMEX Henry Hub | Nov’18 – Dec’ 18 | (0.46 | ) | |||||||
225,000 | WAHA | NYMEX Henry Hub | Jan’19 – Mar’ 19 | (0.46 | ) |
(1) | Represents short swaps that fix the basis differentials (i) between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub and (ii) between WAHA and NYMEX Henry Hub. |
8. ASSET RETIREMENT OBLIGATIONS
A summary of the changes in asset retirement obligations is included in the table below:
Nine Months Ended September 30, 2017 | ||||
(in thousands) | ||||
Balance, beginning of year | $ | 66,028 | ||
Liabilities incurred | 1,202 | |||
Liabilities assumed with acquired producing properties | 705 | |||
Liabilities settled | (6,083 | ) | ||
Liabilities transferred in disposition of properties | (47 | ) | ||
Revisions to estimates | 5,860 | |||
Accretion expense | 1,447 | |||
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Balance, September 30, 2017 | 69,112 | |||
Less: Current portion | 3,960 | |||
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Long-term portion | $ | 65,152 | ||
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The total revisions to estimates include approximately $2.6 million related to additions to oil and natural gas properties with the remaining revisions related to the difference between our beginning asset retirement obligation and the actual settlement amounts for the nine months ended September 30, 2017.
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9. LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER
Long-term debt, net and notes payable to founder consists of the following:
September 30, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Senior secured revolving credit facility | $ | 75,065 | $ | 40,622 | ||||
7.875% senior unsecured notes due 2024 | 500,000 | 500,000 | ||||||
Unamortized deferred financing costs | (9,818 | ) | (10,717 | ) | ||||
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Total long-term debt, net | $ | 565,247 | $ | 529,905 | ||||
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Notes payable to founder | $ | 27,861 | $ | 26,957 | ||||
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Senior Secured Revolving Credit Facility.In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (a) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (b) permits us to make aone-time cash distribution of no more than $1.0 million to a limited partner. As of September 30, 2017, we had $75.1 million outstanding with $234.6 million of available borrowing capacity under the credit facility. The letters of credit outstanding as of September 30, 2017 and December 31, 2016 were approximately $5.3 million and $7.6 million, respectively. The borrowing base is currently $315.0 million and is redetermined semi-annually in May and November of each year. The principal amount is payable on the maturity date of November 10, 2020.
The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The Reference Rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s Reference Rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 4.75% as of September 30, 2017 and 4.00% as of December 31, 2016.
The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.
The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended of not greater than 4.0 to 1.0.
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As of September 30, 2017, we were in compliance with all financial covenants of the credit facility.
Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 which were issued at par by the Company and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.
The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.
The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes (the “indenture”)) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.
Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.
As of September 30, 2017, we were in compliance with the indentures governing the senior notes.
Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.9 million and $27.0 million at September 30, 2017 and December 31, 2016, respectively. The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity.
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These Founder Notes are subordinate to the paid-in-kind notes of High Mesa. The Founder Notes are also subordinated to the rights of High Mesa Holdings, LP (“HMH”) and Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone”) to receive distributions under our Amended Partnership Agreement and subordinated to the rights of the holders of Series B preferred stock of High Mesa to receive payments. Our founder shall convert the Founder Notes into equity interests in HMH immediately prior to the closing of the business combination with Silver Run Acquisition Corporation II. See Note 13 for further details.
Interest on the Founder Notes amounted to $0.9 million for each of the nine months ended September 30, 2017 and 2016. Such amounts have been added to the balance of the Founder Notes.
Deferred financing costs. As of September 30, 2017, we had $11.8 million of deferred financing costs related to the credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $9.8 million related to the senior notes are netted with long-term debt on the condensed consolidated balance sheet as of September 30, 2017. Deferred financing costs of $1.9 million related to the credit facility are included in deferred financing costs, net on the condensed consolidated balance sheets at September 30, 2017. Amortization of deferred financing costs recorded for the nine months ended September 30, 2017 and 2016 was $2.2 million and $3.0 million, respectively. The amortization of these costs are included in interest expense on the condensed consolidated statements of operations.
The credit facility and the senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.
10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the details of accounts payable and accrued liabilities:
September 30, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Capital expenditures | $ | 42,621 | $ | 15,155 | ||||
Revenues and royalties payable | 23,010 | 12,187 | ||||||
Operating expenses/taxes | 18,485 | 12,975 | ||||||
Interest | 12,903 | 2,627 | ||||||
Compensation | 3,296 | 5,302 | ||||||
Derivative settlement payable | 665 | 1,126 | ||||||
Other | 721 | 1,164 | ||||||
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Total accrued liabilities | 101,701 | 50,536 | ||||||
Accounts payable | 42,845 | 29,174 | ||||||
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Accounts payable and accrued liabilities | $ | 144,546 | $ | 79,710 | ||||
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11. COMMITMENTS AND CONTINGENCIES
Contingencies
Environmental claims: Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various
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environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at September 30, 2017.
Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.
Litigation:On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of September 30, 2017, we have accrued approximately $3.2 million ($0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years.
On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly-owned subsidiary (“OEA”), Alta Mesa Services, LP, our wholly-owned subsidiary (“AMS”), and the Company (collectively, the “AMH Parties”) claiming royalty underpayment ornon-payment of royalty. The suit against the AMH Parties alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. As of September 30, 2017, we believe losses are probable and estimable in connection with this litigation and have accrued approximately $4.5 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets.
Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.
Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted performance appreciation rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the
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Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During the first nine months of 2017, we granted 308,800 new PARs with a SIDV of $40 and terminated 1,400 PARs with a SIDV of $40, resulting in 883,300 PARs issued at a weighted average of $37.91 as of September 30, 2017. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our condensed consolidated financial statements at September 30, 2017 or December 31, 2016.
12. SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from lows experienced since such decline, forecasted prices for both oil and natural gas continue to remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Sustained low oil or natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas and natural gas liquids price derivative contracts. See Note 7.
13. PARTNERS’ CAPITAL
Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Sixth Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”). Our Amended Partnership Agreement currently provides for two classes of limited partners, Class A and Class B. Our limited partners include our General Partner, HMH and Riverstone.
On August 16, 2017, we entered into a Contribution Agreement (the “Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), HMH, High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of HMH. Pursuant to the Contribution Agreement, SRII will acquire from HMH (i) all of its limited partner interest in us and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the HMH will receive: (i) 220,000,000 common units as adjusted of SRII Opco, LP, a Delaware limited partnership and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million inearn-out consideration in the form of common units of SRII Opco, LP (the“Earn-out Consideration”). TheEarn-out Consideration will be paid as set forth below if the20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:
20-Day VWAP | Earn-Out Consideration | |
$14.00 | 10,714,285 Common Units | |
$16.00 | 9,375,000 Common Units | |
$18.00 | 13,888,889 Common Units | |
$20.00 | 12,500,000 Common Units |
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Additionally, HMH will purchasenon-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.
The Contribution Agreement contains customary representations and warranties andpre-closing covenants, with the representations and warranties not survive the closing. Additionally, prior to closing, we have agreed to transfer to HMH all assets and liabilities related to thenon-STACK assets. The closing of the Contribution Agreement is subject to (i) the approval of the SRII stockholders, (ii) the simultaneous closing of the contribution agreement by and among SRII, KFM Holdco, LLC, a Delaware limited liability company, Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”) and the equity owners party thereto pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher, (iii) a SRII Opco, LP leverage ratio of less than 1.5x, (iv) certain regulatory approvals and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.
On August 16, 2017, our General Partner, HMH and Riverstone entered into the Amended Partnership Agreement. The Amended Partnership Agreement reflects, among other things, certain changes in our ownership, and provides for certain preemptive rights,tag-along rights, and drag-along rights for the limited partners. In connection with the Amended Partnership Agreement, our limited partners at the time transferred their interests in us to HMH. The Amended Partnership Agreement also reflects the admission of Riverstone and HMH to the Company as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK andnon-STACK assets.
Riverstone was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in us with respect to the economic rights to the STACK assets. We used all of the capital contribution to pay down our credit facility.
On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.
Contribution, Distribution and Income Allocation: The Amended Partnership Agreement specifies the manner in which we will make cash distributions to our partners.
Distributions from Operations.Current distributions of Net Cash Flow and distributions upon the liquidation, sale, merger, consolidation, dissolution or winding up of the Company shall be made by the General Partner as described below. The General Partner shall have sole discretion to determine the timing of any distribution and the aggregate amounts available for such distribution and such distributions will be made:
• | With respect to distributions of Net Cash Flow attributable to the STACK Assets, one hundred percent (100%) to the Class A Partners Pro Rata. Notwithstanding the foregoing, to the extent the Company makes a payment under the Founder Notes, such payment shall be treated as an advance against and, thus, shall reduce the amount otherwise distributable to HMH or its permitted transferees under the Partnership Agreement. |
• | With respect to distributions of Net Cash Flow attributable to theNon-STACK Assets, one hundred percent (100%) to the Class B Partners Pro Rata. |
Net cash flow means all cash flow, receipts and revenues generated by the Company minus amounts necessary for (i) operating expenses (as defined in the Amended Partnership Agreement), (ii) a reserve fund for future operating expenses, (iii) debt service of the Company, or (iv) any other expenses of the Company. STACK assets
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means (a) interests in each of Alta Mesa Finance Services Corp., a Delaware corporation, Oklahoma Energy Acquisitions, LP, a Texas limited partnership, and Alta Mesa Services, LP, a Texas limited partnership, (b) all assets held by each of the foregoing as of the date hereof and (c) all oil and gas properties acquired by the Company or any of its subsidiaries after the date hereof in any of Kingfisher, Garfield, Major, Blaine, Logan, Canadian, Dewey, Woodward and Oklahoma counties, in each case, in the State of Oklahoma.
On December 31, 2016, High Mesa purchased from BCE and contributed interest in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected during the first quarter of 2017. There were no contributions during the first nine months of 2016.
14. RELATED PARTY TRANSACTIONS
We entered into a promissory note receivable with our affiliate Northwest Gas Processing, LLC, a Delaware limited liability company (“NWGP”), effective September 29, 2017, for approximately $1.5 million. The promissory note was issued by NWGP to us and bears interest (or paid-in-kind interest from time to time) on the principal balance at a rate of 8% per annum, with interest payable in quarterly installments beginning January 1, 2018, and matures on February 28, 2019. Subsequent to quarter end, the $1.5 million promissory note was transferred from NWGP to High Mesa Services, LLC, a subsidiary of our parent company High Mesa.
15. SUBSIDIARY GUARANTORS
All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company, we have no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries. There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Alta Mesa Holdings, LP and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Alta Mesa Holdings, LP and Subsidiaries (collectively, the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners’ capital (deficit) and cash flows for each of the three years in the period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Alta Mesa Holdings, LP and Subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/S/ BDO USA, LLP
Houston, Texas
March 30, 2017
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
December 31, 2016 | December 31, 2015 | |||||||
(in thousands) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 7,185 | $ | 8,869 | ||||
Short-term restricted cash | 433 | 105 | ||||||
Accounts receivable, net of allowance of $889 and $1,402, respectively | 37,611 | 27,111 | ||||||
Other receivables | 8,061 | 18,526 | ||||||
Receivables due from affiliate | 8,883 | 1,053 | ||||||
Prepaid expenses and other current assets | 3,986 | 4,774 | ||||||
Derivative financial instruments | 83 | 62,631 | ||||||
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|
| |||||
Total current assets | 66,242 | 123,069 | ||||||
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|
| |||||
PROPERTY AND EQUIPMENT | ||||||||
Oil and natural gas properties, successful efforts method, net | 712,162 | 525,942 | ||||||
Other property and equipment, net | 9,731 | 11,097 | ||||||
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|
| |||||
Total property and equipment, net | 721,893 | 537,039 | ||||||
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| |||||
OTHER ASSETS | ||||||||
Investment in LLC – cost | 9,000 | 9,000 | ||||||
Deferred financing costs, net | 3,029 | 1,199 | ||||||
Notes receivable due from affiliate | 9,987 | 9,213 | ||||||
Deposits and other long-term assets | 2,977 | 1,370 | ||||||
Derivative financial instruments | 723 | 41,635 | ||||||
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| |||||
Total other assets | 25,716 | 62,417 | ||||||
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| |||||
TOTAL ASSETS | $ | 813,851 | $ | 722,525 | ||||
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LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT) | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable and accrued liabilities | $ | 79,710 | $ | 80,758 | ||||
Advances fromnon-operators | 4,058 | 1,381 | ||||||
Advances from related party | 42,528 | — | ||||||
Asset retirement obligations | 4,900 | 2,592 | ||||||
Derivative financial instruments | 21,207 | — | ||||||
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| |||||
Total current liabilities | 152,403 | 84,731 | ||||||
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| |||||
LONG-TERM LIABILITIES | ||||||||
Asset retirement obligations, net of current portion | 61,128 | 60,491 | ||||||
Long-term debt, net | 529,905 | 717,775 | ||||||
Notes payable to founder | 26,957 | 25,748 | ||||||
Derivative financial instruments | 4,482 | — | ||||||
Other long-term liabilities | 6,870 | 10,829 | ||||||
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| |||||
Total long-term liabilities | 629,342 | 814,843 | ||||||
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| |||||
TOTAL LIABILITIES | 781,745 | 899,574 | ||||||
Commitments and Contingencies (Note 12) | ||||||||
PARTNERS’ CAPITAL (DEFICIT) | 32,106 | (177,049 | ) | |||||
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TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT) | $ | 813,851 | $ | 722,525 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
OPERATING REVENUES AND OTHER | ||||||||||||
Oil | $ | 163,677 | $ | 199,799 | $ | 347,842 | ||||||
Natural gas | 30,953 | 30,621 | 65,002 | |||||||||
Natural gas liquids | 15,663 | 10,864 | 18,281 | |||||||||
Other revenues | 415 | 682 | 1,003 | |||||||||
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Total operating revenues | 210,708 | 241,966 | 432,128 | |||||||||
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Gain on sale of assets | 3,542 | 67,781 | 87,520 | |||||||||
Gain (loss) on derivative contracts | (40,460 | ) | 124,141 | 96,559 | ||||||||
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Total operating revenues and other | 173,790 | 433,888 | 616,207 | |||||||||
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OPERATING EXPENSES | ||||||||||||
Lease and plant operating expense | 56,893 | 67,706 | 64,686 | |||||||||
Marketing and transportation expense | 13,326 | 4,030 | 9,134 | |||||||||
Production and ad valorem taxes | 10,750 | 15,131 | 28,214 | |||||||||
Workover expense | 4,714 | 6,511 | 8,961 | |||||||||
Exploration expense | 24,777 | 42,718 | 61,912 | |||||||||
Depreciation, depletion, and amortization expense | 92,901 | 143,969 | 141,804 | |||||||||
Impairment expense | 16,306 | 176,774 | 74,927 | |||||||||
Accretion expense | 2,174 | 2,076 | 2,198 | |||||||||
General and administrative expense | 41,758 | 44,454 | 69,198 | |||||||||
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Total operating expenses | 263,599 | 503,369 | 461,034 | |||||||||
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INCOME (LOSS) FROM OPERATIONS | (89,809 | ) | (69,481 | ) | 155,173 | |||||||
OTHER INCOME (EXPENSE) | ||||||||||||
Interest expense | (60,884 | ) | (62,473 | ) | (55,812 | ) | ||||||
Interest income | 894 | 723 | 15 | |||||||||
Loss on extinguishment of debt | (18,151 | ) | — | — | ||||||||
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Total other income (expense) | (78,141 | ) | (61,750 | ) | (55,797 | ) | ||||||
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INCOME (LOSS) BEFORE STATE INCOME TAXES | (167,950 | ) | (131,231 | ) | 99,376 | |||||||
Provision for (benefit from) state income taxes | (29 | ) | 562 | 176 | ||||||||
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NET INCOME (LOSS) | $ | (167,921 | ) | $ | (131,793 | ) | $ | 99,200 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(in thousands)
BALANCE, DECEMBER 31, 2013 | $ | (160,107 | ) | |
DISTRIBUTIONS | (539 | ) | ||
NET INCOME | 99,200 | |||
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BALANCE, DECEMBER 31, 2014 | (61,446 | ) | ||
CONTRIBUTIONS | 20,000 | |||
DISTRIBUTIONS | (3,810 | ) | ||
NET LOSS | (131,793 | ) | ||
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BALANCE, DECEMBER 31, 2015 | (177,049 | ) | ||
CONTRIBUTIONS | 377,076 | |||
NET LOSS | (167,921 | ) | ||
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BALANCE, DECEMBER 31, 2016 | $ | 32,106 | ||
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The accompanying notes are an integral part of these consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | (167,921 | ) | $ | (131,793 | ) | $ | 99,200 | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion, and amortization expense | 92,901 | 143,969 | 141,804 | |||||||||
Impairment expense | 16,306 | 176,774 | 74,927 | |||||||||
Accretion expense | 2,174 | 2,076 | 2,198 | |||||||||
Amortization of deferred financing costs | 3,905 | 3,392 | 2,885 | |||||||||
Amortization of debt discount | 468 | 510 | 510 | |||||||||
Dry hole expense | 419 | 22,708 | 30,294 | |||||||||
Expired leases | 11,158 | 6,526 | 4,319 | |||||||||
(Gain) loss on derivative contracts | 40,460 | (124,141 | ) | (96,559 | ) | |||||||
Settlements of derivative contracts | 88,689 | 106,949 | 9,493 | |||||||||
Loss on extinguishment of debt | 18,151 | — | — | |||||||||
Interest converted into debt | 1,209 | 1,208 | 1,209 | |||||||||
Interest on notes receivable due from affiliate | (774 | ) | (713 | ) | — | |||||||
Gain on sale of assets | (3,542 | ) | (67,781 | ) | (87,520 | ) | ||||||
Changes in assets and liabilities: | ||||||||||||
Restricted cash unrelated to property divestiture | (328 | ) | — | (106 | ) | |||||||
Accounts receivable | (10,500 | ) | 16,470 | (95 | ) | |||||||
Other receivables | 10,465 | (10,288 | ) | (5,686 | ) | |||||||
Receivables due from affiliate | 45 | (1,725 | ) | — | ||||||||
Prepaid expenses and othernon-current assets | (819 | ) | (2,269 | ) | 7,251 | |||||||
Advances from related party | 42,528 | — | — | |||||||||
Settlement of asset retirement obligation | (2,125 | ) | (1,794 | ) | (3,942 | ) | ||||||
Accounts payable, accrued liabilities, and other liabilities | (11,493 | ) | 3,900 | 4,702 | ||||||||
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NET CASH PROVIDED BY OPERATING ACTIVITIES | 131,376 | 143,978 | 184,884 | |||||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures for property and equipment | (214,061 | ) | (223,604 | ) | (366,090 | ) | ||||||
Acquisitions | (11,527 | ) | (48,202 | ) | (18,110 | ) | ||||||
Proceeds from sale of property | 1,290 | 141,404 | 177,476 | |||||||||
Proceeds from property divestiture classified as restricted cash | — | — | 41,590 | |||||||||
Investment in restricted cash related to property divestitures | — | 24,587 | (24,587 | ) | ||||||||
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NET CASH USED IN INVESTING ACTIVITIES | (224,298 | ) | (105,815 | ) | (189,721 | ) | ||||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Proceeds from long-term debt | 222,557 | 252,500 | 169,500 | |||||||||
Repayments of long-term debt | (333,935 | ) | (295,020 | ) | (169,270 | ) | ||||||
Repayments of senior secured term loan | (127,708 | ) | — | — | ||||||||
Repurchase of senior notes due 2018 | (459,391 | ) | — | — | ||||||||
Proceeds from issuance of senior notes due 2024 | 500,000 | — | — | |||||||||
Additions to deferred financing costs | (13,747 | ) | (4,313 | ) | (42 | ) | ||||||
Capital distributions | — | (3,810 | ) | (539 | ) | |||||||
Capital contributions | 303,462 | 20,000 | — | |||||||||
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NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | 91,238 | (30,643 | ) | (351 | ) | |||||||
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1,684 | ) | 7,520 | (5,188 | ) | |||||||
CASH AND CASH EQUIVALENTS, beginning of period | 8,869 | 1,349 | 6,537 | |||||||||
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CASH AND CASH EQUIVALENTS, end of period | $ | 7,185 | $ | 8,869 | $ | 1,349 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
NOTE 1 – NATURE OF OPERATIONS
Nature of Operations. Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin referred to as the STACK. The STACK is an acronym describing both its location–Sooner Trend Anadarko Basin Canadian and Kingfisher County–and the multiple, stacked productive formations present in the area. Our operations also include other oil and natural gas interests in Texas, Louisiana and Florida.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).
Principles of Consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.
Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquired properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.
Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2016, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or unclaimed property for pooling orders in Oklahoma.
Accounts Receivable. Our receivables arise primarily from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our
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overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recovernon-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts.
Accounts receivable consisted of the following:
As of December 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Oil, natural gas and natural gas liquids sales | $ | 25,149 | $ | 17,865 | ||||
Joint interest billings | 13,344 | 10,162 | ||||||
Other | 7 | 486 | ||||||
Allowance for doubtful accounts | (889 | ) | (1,402 | ) | ||||
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| |||||
Total accounts receivable, net | $ | 37,611 | $ | 27,111 | ||||
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See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, respectively.
Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.
Deferred Financing Costs.The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets.
Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Unproved Properties – Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
Exploration Expense – Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet pending determination of whether the well has discovered proved commercial reserves. See Note 5 for further details. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.
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Proved Oil and Natural Gas Properties – Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
Impairment – The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
Our evaluation of the Company’s proved properties resulted in impairment expense of $16.1 million, $172.0 million and $72.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, primarily due to lower forecasted commodity prices.
Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on aproperty-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2016, 2015 and 2014, impairment expense of unproved properties was $0.2 million, $4.8 million, and $2.0 million, respectively.
Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2016, 2015 and 2014, respectively, the Company did not record any impairment expense related to other long-lived assets.
Depreciation, Depletion and Amortization – Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using theunit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
DD&A expense for the years ended December 31, 2016, 2015 and 2014 related to oil and natural gas properties was $90.0 million, $140.9 million, and $139.0 million, respectively.
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Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense fornon-oil and gas property and equipment for the years ended December 31, 2016, 2015 and 2014 was $2.9 million, $3.0 million, and $2.8 million respectively.
Investments. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.
Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally withmonth-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13.
Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.
Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 6 for information on fair value).
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows.
Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.
Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016.
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The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.
We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using atwo-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2016 and 2015. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2016, 2015 or 2014.
The Company’s tax returns for the years ended December 31, 2013 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.
Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. In December 2016, we issued $500 million in aggregate principal amount of our 7.875% senior unsecured notes due 2024 (the “2024 Notes”). We have estimated the fair value of the 2024 Notes payable at $520 million on December 31, 2016. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments and details related to the 2024 Notes, refer to Note 6 – Fair Value Disclosures and Note 10 – Long-Term Debt, Net.
Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASUNo. 2014-09,Revenue from Contracts with Customers.The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on
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the opening balance sheet. In August 2015, the FASB issued ASUNo. 2015-14,Deferral of the Effective Date (“ASU2015-14”). ASU2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements.
In January 2016, the FASB issued ASUNo. 2016-01,Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
In February 2016, the FASB issued ASU2016-02, Leases (Topic 842)which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) aright-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company does not plan to adopt the standard early. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.
In August 2016, the FASB issued ASUNo. 2016-15,Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.
In October 2016, the FASB issued ASUNo. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control. This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements.
In November 2016, the FASB issued ASU2016-18,Statement of Cash Flows: Restricted Cash,which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.
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In January 2017, the FASB issued ASUNo. 2017-01,Clarifying the Definition of a Business,which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
NOTE 3 – SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow disclosures andnon-cash investing and financing activities are presented below:
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Supplemental cash flow information: | ||||||||||||
Cash paid for interest | $ | 74,694 | $ | 56,579 | $ | 51,219 | ||||||
Cash paid (received) for state income taxes, net of refunds | 285 | 751 | (123 | ) | ||||||||
Non-cash investing and financing activities: | ||||||||||||
Change in asset retirement obligations | 2,719 | 487 | 2,643 | |||||||||
Asset retirement obligations assumed, purchased properties | — | — | 3,002 | |||||||||
Change in accruals or liabilities for capital expenditures | 12,375 | (34,160 | ) | 23,858 | ||||||||
Divestiture of oil and gas properties | — | — | (34,000 | ) | ||||||||
Acquisition of property and land | — | 2,473 | — | |||||||||
Contribution of interests in oil and gas properties | 65,740 | — | — | |||||||||
Contribution receivable | 7,875 | — | — |
NOTE 4 – SIGNIFICANT ACQUISITIONS AND DIVESTITURES
2016 Activity
During 2016, we acquired approximately $10.6 million of oil and gas properties in Oklahoma which were primarily related to unevaluated leasehold.
On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) purchased from BCE and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. The Company accounted for the Contributed Wells as a business combination and therefore, recorded the contribution at their estimated contribution date fair value. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.
The unaudited pro forma combined financial results, had the contribution of the Contributed Wells occurred at January 1, 2016, are provided below. The Contributed Wells came online during 2016, therefore, no unaudited pro forma combined results are shown for the beginning of the comparable prior year.
Total operating revenues and other | Net loss | |||||||
(in thousands) (unaudited) | ||||||||
Pro forma results for the combined entity for the year ended December 31, 2016 | $ | 199,982 | $ | (157,230 | ) |
This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the contribution had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
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2015 Activity
Alta Mesa Eagle, LLC Divestiture
On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional FundXIV-A, L.P. and EnerVest Energy Institutional FundXIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”). AME owned our remainingnon-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas. In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area. The effective date of the transaction (the “Effective Date”) is July 1, 2015.
The aggregate cash purchase price for the Membership Interests was $125.0 million subject to certain adjustments, consisting of $118.0 million (the “Base Purchase Price”), and additional contingent payments of approximately $7.0 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received. The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.
The sale of AME contributed approximately $68.9 million inpre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118.5 million inpre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below.
Kingfisher Leasehold Acquisition
On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments. The effective date of the acquisition was April 1, 2015. The purchase was funded with borrowings under our senior secured revolving credit facility.
2014 Activity
Eagleville Divestiture
On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville Divestiture”). The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014. We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017. Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014. The initial cash purchase price was $173.0 million, subsequently adjusted to approximately $171.0 million for settlement adjustments. The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date. As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE. We recorded a gain on sale from the Eagleville Divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained.
The sold portion of Eagleville field contributed approximately $11.1 million inpre-tax income in the first quarter of 2014, prior to its sale.
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Hilltop Divestiture
On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a gain on the sale of $15.9 million. As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.
The Hilltop interests contributed approximately $7.7 million in netpre-tax income during the year ended December 31, 2014.
NOTE 5 – PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
December 31, 2016 | December 31, 2015 | |||||||
(in thousands) | ||||||||
OIL AND NATURAL GAS PROPERTIES | ||||||||
Unproved properties | $ | 116,311 | $ | 127,551 | ||||
Accumulated impairment | (65 | ) | (2,684 | ) | ||||
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Unproved properties, net | 116,246 | 124,867 | ||||||
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Proved oil and natural gas properties | 1,611,249 | 1,345,482 | ||||||
Accumulated depreciation, depletion, amortization and impairment | (1,015,333 | ) | (944,407 | ) | ||||
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Proved oil and natural gas properties, net | 595,916 | 401,075 | ||||||
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TOTAL OIL AND NATURAL GAS PROPERTIES, net | 712,162 | 525,942 | ||||||
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OTHER PROPERTY AND EQUIPMENT | ||||||||
Land | 4,730 | 3,868 | ||||||
Office furniture and equipment, vehicles | 19,446 | 18,794 | ||||||
Accumulated depreciation | (14,445 | ) | (11,565 | ) | ||||
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OTHER PROPERTY AND EQUIPMENT, net | 9,731 | 11,097 | ||||||
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TOTAL PROPERTY AND EQUIPMENT, net | $ | 721,893 | $ | 537,039 | ||||
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Capitalized Exploratory Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2016, 2015, and 2014. The table does not include amounts that were capitalized and either subsequently expensed within the same year.
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Balance, beginning of year | $ | 6,006 | $ | 13,301 | $ | 20,317 | ||||||
Additions to capitalized well costs pending determination of proved reserves | 3,736 | 4,364 | 15,870 | |||||||||
Reclassifications to proved properties | (7,484 | ) | (8,583 | ) | (6,593 | ) | ||||||
Capitalized exploratory well costs charged to expense | (169 | ) | (3,076 | ) | (16,293 | ) | ||||||
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Balance, end of year | $ | 2,089 | $ | 6,006 | $ | 13,301 | ||||||
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The ending balance in capitalized exploratory well costs includes the costs of five wells primarily in three prospects that were capitalized for periods greater than one year at December 31, 2016. We have capitalized $0.7 million and $3.0 million of exploratory well costs covering periods greater than one year at December 31, 2016 and 2015. We continue to assess and evaluate these projects.
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NOTE 6 – FAIR VALUE DISCLOSURES
The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.
We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2.
Our senior notes are carried at historical cost. We estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.
Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $33.9 million were written down to their fair value of $17.6 million, resulting in an impairment charge of $16.3 million for the year ended December 31, 2016. Oil and natural gas properties with a carrying amount of $499.6 million were written down to their fair value of $322.8 million, resulting in an impairment charge of $176.8 million for the year ended December 31, 2015. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $1.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2016. We recorded a total of $2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015.
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The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(in thousands) | ||||||||||||||||
At December 31, 2016: | ||||||||||||||||
Financial Assets: | ||||||||||||||||
Derivative contracts for oil and natural gas | — | $ | 15,773 | — | $ | 15,773 | ||||||||||
Financial Liabilities: | ||||||||||||||||
Derivative contracts for oil and natural gas | — | $ | 40,656 | — | $ | 40,656 | ||||||||||
At December 31, 2015: | ||||||||||||||||
Financial Assets: | ||||||||||||||||
Derivative contracts for oil and natural gas | — | $ | 166,106 | — | $ | 166,106 | ||||||||||
Financial Liabilities: | ||||||||||||||||
Derivative contracts for oil and natural gas | — | $ | 61,840 | — | $ | 61,840 |
The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between the benchmark index price and the specific locational index pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our senior secured revolving credit facility described in Note 10 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes.
From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.
We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we usemark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statements of operations at each reporting date.
Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.
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The following table summarizes the fair value (see Note 6 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:
December 31, 2016 | ||||||||||||
Balance sheet location | Gross Fair Value of Assets | Gross amounts offset against assets in the Balance Sheet | Net Fair Value of Assets presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 3,296 | $ | (3,213 | ) | $ | 83 | |||||
Derivative financial instruments, long-term assets | 12,477 | (11,754 | ) | 723 | ||||||||
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Total | $ | 15,773 | $ | (14,967 | ) | $ | 806 | |||||
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Balance sheet location | Gross Fair Value of Liabilities | Gross amounts offset against liabilities in the Balance Sheet | Net Fair Value of Liabilities presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 24,420 | $ | (3,213 | ) | $ | 21,207 | |||||
Derivative financial instruments, long-term liabilities | 16,236 | (11,754 | ) | 4,482 | ||||||||
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Total | $ | 40,656 | $ | (14,967 | ) | $ | 25,689 | |||||
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December 31, 2015 | ||||||||||||
Balance sheet location | Gross Fair Value of Assets | Gross amounts offset against assets in the Balance Sheet | Net Fair Value of Assets presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 86,000 | $ | (23,369 | ) | $ | 62,631 | |||||
Derivative financial instruments, long-term assets | 80,106 | (38,471 | ) | 41,635 | ||||||||
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Total | $ | 166,106 | $ | (61,840 | ) | $ | 104,266 | |||||
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Balance sheet location | Gross Fair Value of Liabilities | Gross amounts offset against liabilities in the Balance Sheet | Net Fair Value of Liabilities presented in the Balance Sheet | |||||||||
(in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 23,369 | $ | (23,369 | ) | $ | — | |||||
Derivative financial instruments, long-term liabilities | 38,471 | (38,471 | ) | — | ||||||||
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Total | $ | 61,840 | $ | (61,840 | ) | $ | — | |||||
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The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:
Derivatives not designated as hedging instruments under ASC 815 | Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Gain (loss) on derivative contracts | ||||||||||||
Oil commodity contracts | $ | (36,572 | ) | $ | 113,295 | $ | 82,510 | |||||
Natural gas commodity contracts | (2,410 | ) | 10,712 | 14,049 | ||||||||
Natural gas liquids commodity contracts | (1,478 | ) | 134 | — | ||||||||
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Total gain (loss) on derivative contracts | $ | (40,460 | ) | $ | 124,141 | $ | 96,559 | |||||
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Other receivables include $7.8 million and $17.5 million of derivative positions settled, but not yet received as of December 31, 2016 and 2015, respectively.
Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, toset-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.
We had the following open derivative contracts for crude oil at December 31, 2016:
OIL DERIVATIVE CONTRACTS
Volume in Bbls | Weighted Average | Range | ||||||||||||||
Period and Type of Contract | High | Low | ||||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | 1,460,000 | $ | 46.93 | $ | 48.43 | $ | 45.00 | |||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 2,075,000 | 60.46 | 85.00 | 54.40 | ||||||||||||
Long Put Options | 1,527,500 | 48.39 | 50.00 | 47.00 | ||||||||||||
Short Put Options | 1,527,500 | 37.19 | 40.00 | 35.00 | ||||||||||||
2018 | ||||||||||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 1,825,000 | 60.64 | 60.90 | 60.50 | ||||||||||||
Long Put Options | 1,825,000 | 50.00 | 50.00 | 50.00 | ||||||||||||
Short Put Options | 1,825,000 | 40.00 | 40.00 | 40.00 | ||||||||||||
2019 | ||||||||||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 1,241,000 | 62.90 | 63.00 | 62.75 | ||||||||||||
Long Put Options | 1,241,000 | 50.00 | 50.00 | 50.00 | ||||||||||||
Short Put Options | 1,241,000 | 37.50 | 37.50 | 37.50 |
We had the following open derivative contracts for natural gas at December 31, 2016:
NATURAL GAS DERIVATIVE CONTRACTS
Volume in MMBtu | Weighted Average | Range | ||||||||||||||
Period and Type of Contract | High | Low | ||||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | 450,000 | $ | 2.47 | $ | 2.47 | $ | 2.47 | |||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 10,220,000 | 3.68 | 3.94 | 3.56 | ||||||||||||
Long Put Options | 9,320,000 | 3.09 | 3.30 | 3.00 | ||||||||||||
Long Call Options | 1,125,000 | 3.44 | 3.56 | 3.25 | ||||||||||||
Short Put Options | 9,320,000 | 2.56 | 2.70 | 2.50 | ||||||||||||
2018 | ||||||||||||||||
Collar Contracts | ||||||||||||||||
Short Call Options | 6,132,000 | 5.34 | 5.53 | 4.00 | ||||||||||||
Long Put Options | 5,475,000 | 4.50 | 4.50 | 4.50 | ||||||||||||
Short Put Options | 5,475,000 | 4.00 | 4.00 | 4.00 |
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In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks.
We had the following open derivative contracts for natural gas liquids at December 31, 2016:
NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS
Volume in Gal | Weighted Average | Range | ||||||||||||||
Period and Type of Contract | High | Low | ||||||||||||||
2017 | ||||||||||||||||
Price Swap Contracts | 5,371,800 | $ | 0.46 | $ | 0.47 | $ | 0.45 |
We had the following open financial basis swap contracts for natural gas at December 31, 2016:
BASIS SWAP DERIVATIVE CONTRACTS
Volume in MMBtu | Reference Price 1 (1) | Reference Price 2 (1) | Period | Weighted Average Spread ($ per MMBtu) | ||||||
12,470,000 | NYMEX Henry Hub | Tex/OKL Panhandle Eastern Pipeline | Jan’ 17 – Dec’ 17 | $ | (0.24 | ) | ||||
5,910,000 | NYMEX Henry Hub | Tex/OKL Panhandle Eastern Pipeline | Jan’ 18 – Oct’ 18 | (0.27 | ) |
(1) | Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub. |
NOTE 8–ASSET RETIREMENT OBLIGATIONS
A summary of the changes in our asset retirement obligations is included in the table below:
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Balance, beginning of year | $ | 63,083 | $ | 65,193 | $ | 58,838 | ||||||
Liabilities incurred | 1,438 | 1,988 | 1,129 | |||||||||
Liabilities assumed with acquired producing properties | — | — | 3,002 | |||||||||
Liabilities settled | (2,125 | ) | (1,794 | ) | (3,942 | ) | ||||||
Liabilities transferred in sales of properties | (3,036 | ) | (3,149 | ) | (1,886 | ) | ||||||
Revisions to estimates | 4,494 | (1,231 | ) | 5,854 | ||||||||
Accretion expense | 2,174 | 2,076 | 2,198 | |||||||||
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Balance, end of year | 66,028 | 63,083 | 65,193 | |||||||||
Less: Current portion | 4,900 | 2,592 | 3,457 | |||||||||
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Long-term portion | $ | 61,128 | $ | 60,491 | $ | 61,736 | ||||||
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The total revisions included $1.3 million related to additions to property, plant and equipment for the year ended December 31, 2016. Total revisions included $1.5 million related to reductions and $2.9 million related to additions to property, plant and equipment for the years ended December 31, 2015 and 2014, respectively.
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NOTE 9 – RELATED PARTY TRANSACTIONS
We have notes payable to our founder which bear interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 2015, respectively. See Note 10 for further information.
Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions during the years ended December 31, 2016 and 2015 and received $516,500 of capital distributions from us during the year ended December 31, 2014, respectively.
David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at apre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2016, 2015 and 2014 were approximately $146,000, $133,000 and $150,000. The contract may be terminated by either party without penalty upon 30 days’ notice.
David McClure, our Vice President of Facilities and Midstream, and theson-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000, $275,000 and $450,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.
David Pepper, one of our Landmen, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $180,000, $146,000 and $260,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.
On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “joint development agreement”), withBCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Energy Management LLC (“Bayou City”), to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. As described in Note 16, William W. McMullen and Mark Stoner, partners at Bayou City, were appointed to the board of managers of Alta Mesa Holdings GP, LLC, our general partner during the third quarter of 2016. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each. The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. See Notes 4 and 16 for further details. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each. As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 wells to be drilled under the joint development agreement.
Under the joint development agreement, as amended on December 31, 2016, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well. The approximate dollar value of the amount involved in this transaction or Messrs. McMullen or Stoner’s interests in the transaction depends on a number of factors
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outside their control and is not known at this time. As of December 31, 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of the joint development agreement.
During the year ended December 31, 2016, High Mesa contributed $311.3 million to us, of which $7.9 million is included in receivables due from affiliate at December 31, 2016 and the amount was collected subsequent toyear-end. During the year ended December 31, 2015, High Mesa contributed $20 million to us. For additional information, see Note 16 – Partners’ Capital (Deficit). As of December 31, 2016 and 2015, approximately $0.9 million and $1.1 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from affiliates on the consolidated balance sheets.
On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate, Northwest Gas Processing, LLC (“NWGP”), which is a subsidiary of High Mesa. We recorded $25.5 million in other receivables and $8.5 million in long-term notes receivable, while recording no gain or loss on the sale at December 31, 2014. On January 2, 2015, the receivable of $25.5 million was paid in full. The $8.5 million long-term note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the note receivable from our affiliate amounted to $0.8 million and $0.7 million during the years ended December 31, 2016 and 2015, respectively. Such amounts have been added to the balance of the note receivable. On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million.
We are party to a services agreement dated January 1, 2016 with NWGP. Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014. During the year ended December 31, 2016, NWGP was billed for management services provided in the amount of approximately $0.1 million.
On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended and restated on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM for gathering and processing.
Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will remain in effect for a primary term of 15 years from thein-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities.
Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed gathering fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.
Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and
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processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed. Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant.
The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million. The plant commenced operations in the second quarter of 2016. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2016, we accrued approximately $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant. Subsequent toyear-end, Oklahoma Energy entered into an agreement with KFM whereby the Company made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/day for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.
NOTE 10 – LONG TERM DEBT, NET
Long-term debt, net consists of the following:
December 31, 2016 | December 31, 2015 | |||||||
(in thousands) | ||||||||
Senior secured revolving credit facility | $ | 40,622 | $ | 152,000 | ||||
Senior secured term loan | — | 125,000 | ||||||
9.625% senior unsecured notes due 2018 | — | 448,598 | ||||||
7.875% senior unsecured notes due 2024 | 500,000 | — | ||||||
Unamortized deferred financing costs | (10,717 | ) | (7,823 | ) | ||||
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Total long-term debt, net | $ | 529,905 | $ | 717,775 | ||||
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Notes payable to founder | $ | 26,957 | $ | 25,748 | ||||
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Senior Secured Revolving Credit Facility.In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. The amended and restated credit facility, among other things, (i) reaffirms the existing borrowing base amount of $300 million through the new redetermination of the borrowing base, (ii) increases the maximum credit amount from $500 million to $750 million, subject to borrowing base limit (iii) extends the maturity of the credit facility to November 10, 2020 with the completion of a refinancing of the 2018 Notes (as described below), (iv) increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio), and (v) increases our mortgage requirement from 85% of the value of our proven reserves to 90%. Our borrowing base was reduced to $287.5 million from $300 million following the issuance of the 2024 Notes, as described below.
As of December 31, 2016, the Company had $40.6 million outstanding with $239.3 million of available borrowing capacity under the credit facility. The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves
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and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The reference rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 4.00% as of December 31, 2016 and 2.89% as of December 31, 2015. The letters of credit outstanding as of December 31, 2016 and 2015 were $7.6 million and $65,000, respectively.
The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect. As of December 31, 2016, the covenants of the Company’s credit facility prohibit it from making any distributions.
The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0, commencing with the fiscal quarter ending December 31, 2016.
As of December 31, 2016, we were in compliance with all covenants under the credit facility.
Senior Secured Term Loan.On June 2, 2015, we entered into a second lien senior secured term loan agreement (the “term loan facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million. In October 2016, High Mesa contributed $300 million to us from the investment by Bayou City, as described in Note 16. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date.
For the year ended December 31, 2016, the Company recognized a loss of $4.7 million, which included unamortized deferred financing cost write-offs of $2.0 million, and are reflected in loss on extinguishment of debt in the consolidated statements of operations.
Senior Unsecured Notes. On December 8, 2016, the Company and our wholly owned subsidiary Alta Mesa Finances Services Corp. (collectively, the “Issuers”) issued $500.0 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 at par, the 2024 Notes, which resulted in aggregate net proceeds to the Company of $491.3 million, after deducting commission offering expenses. The Company used the proceeds from the issuance of the 2024 Notes to fund the repurchase of the 2018 Notes pursuant to a tender
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offer and the redemption of any of the 2018 Notes that remained outstanding after consummation of the tender offer. The remainder of the proceeds were used to repay a portion of our indebtedness under our credit facility.
The 2024 Notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, the Company may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the 2024 Notes may require the Company to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, the Company may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.
The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of the Company’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Company’s credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of the Company’s subsidiaries that do not guarantee the 2024 Notes.
The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change the Company’s line of business. As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions.
Under the terms of the indenture for the 2024 Notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.
Repurchase and Redemption of 9.625% Senior Unsecured Notes due 2018
On November 30, 2016 we commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016 and on December 8, 2016, we made payment of the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, on December 8, 2016, the Company caused to be deposited, with Wells Fargo Bank, National Association, the Trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the
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2018 Notes. The Satisfaction and Discharge, among other things, discharged the indenture and the obligations of the Company thereunder. As a result of the tender offer and redemption, the Company repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016.
For the year ended December 31, 2016, the Company recognized a loss of $13.5 million, which includes unamortized discountwrite-off of $0.9 million, unamortized deferred financing costswrite-off of $3.2 million, tender premium of $2.5 million and accrued interest of $6.9 million, which is all reflected in loss on extinguishment of debt in the consolidated statements of operations.
Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 2015, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity. Our founder may convert the notes into shares of our Class B partner’s, High Mesa, common stock upon certain conditions in the event of an initial public offering of High Mesa.
These founder notes are unsecured and are subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 16, the founder notes were amended and restated to subordinate them to the paid in kind notes of our Class B partner. The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement, as amended, and subordinated to the rights of the holders of Series B preferred stock to receive payments.
Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes.
Deferred financing costs. As of December 31, 2016, the Company had $13.7 million of deferred financing costs related to the credit facility and the 2024 Notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.7 million related to the 2024 Notes are included in long-term debt on the consolidated balance sheets as of December 31, 2016. Deferred financing costs of $3.0 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2016. Amortization of deferred financing costs recorded for the years ended December 31, 2016, 2015 and 2014 was $3.9 million, $3.4 million and $2.9 million, respectively. These costs are included in interest expense on the consolidated statements of operations. The loss on extinguishment of debt in the consolidated statements of operations included unamortized deferred financing costs write-offs of $5.1 million related to the repayment of the term loan facility and the repurchase and redemption of the 2018 Notes for the year ended December 31, 2016. No deferred financing costs were written off during the years ended December 31, 2015 and 2014.
Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs, at December 31, 2016 are as follows (in thousands):
Year ending December 31, | ||||
2017 | $ | — | ||
2018 | — | |||
2019 | — | |||
2020 | 40,622 | |||
2021 | 26,957 | |||
Thereafter | 500,000 | |||
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| |||
$ | 567,579 | |||
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|
The credit facility and the 2024 Notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due
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and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.
At December 31, 2016, we were in compliance with the covenants of our debt agreements.
NOTE 11 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the detail of accounts payable and accrued liabilities:
December 31, 2016 | December 31, 2015 | |||||||
(in thousands) | ||||||||
Capital expenditures | $ | 15,155 | $ | 10,780 | ||||
Revenues and royalties payable | 12,187 | 5,082 | ||||||
Operating expenses/taxes | 12,975 | 16,092 | ||||||
Interest | 2,627 | 9,919 | ||||||
Compensation | 5,302 | 5,434 | ||||||
Derivatives settlement payable | 1,126 | 11,149 | ||||||
Other | 1,164 | 1,201 | ||||||
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| |||||
Total accrued liabilities | 50,536 | 59,657 | ||||||
Accounts payable | 29,174 | 21,101 | ||||||
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Accounts payable and accrued liabilities | $ | 79,710 | $ | 80,758 | ||||
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NOTE 12 – COMMITMENTS AND CONTINGENCIES
Contingencies
Environmental claims: Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our consolidated financial statements at December 31, 2016.
Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management revised the estimated liability for groundwater contamination in Florida based on our reassessment of our remediation costs and plan, which is pending approval by the State of Florida. As of December 31, 2016, our revised estimated remediation liability was approximately $0.1 million. As of December 31, 2015, we had estimated a liability of $1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the accompanying consolidated balance sheets.
Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.
Litigation:On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary, which we acquired in 2010), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope
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Field in St. Charles Parish. Plaintiffs claim they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of December 31, 2016, we have accrued approximately $4.0 million ($0.8 million in current liabilities and $3.2 million in other long-term liabilities) in connection with the settlement. The settlement requires payment over the term of six years.
Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.
We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.
Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial stipulated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During 2016, we granted 360,000 PARs and terminated 26,200 PARs with a SIDV of $40, resulting in 575,300 PARs issued at a weighted average value of $36.78. Subsequent to year end, 306,300 PARs were granted with a SIDV of $40 and 500 PARs with a SIDV of $40 were terminated, resulting in 881,100 PARs issued at a weighted average value of $37.90. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2016 or 2015.
Commitments
Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for four years or less. Total rent expense, net of sublease income, including office space and compressors, for the years ended December 31, 2016, 2015, and 2014 amounted to approximately $5.7 million, $4.8 million, and $5.7 million, respectively.
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At December 31, 2016, the future minimum base rentals fornon-cancelable operating leases are as follows:
Year Ending December 31, | Amount (1) (in thousands) | |||
2017 | $ | 3,956 | ||
2018 | 1,453 | |||
2019 | 1,545 | |||
2020 | 1,593 | |||
2021 | 1,620 | |||
Thereafter | 1,207 | |||
|
| |||
$ | 11,374 | |||
|
|
(1) | These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019. |
Additionally, at December 31, 2016, the Company had posted bonds in the aggregate amount of $24.0 million, primarily to cover future abandonment costs.
NOTE 13 – SIGNIFICANT CONCENTRATIONS
We sell our oil and natural gas primarily through a marketing contract with AEM. AEM is our marketing agent and acts on our behalf to market our oil and natural gas to any purchasers identified by AEM. We are a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally withmonth-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. The fee charged to us by AEM for marketing is recorded as a marketing and transportation expense. Our marketing agreement with AEM commenced in June 2013. This agreement will terminate in June 2018, with additional provisions for extensions beyond five years and for early termination. AEM marketed majority of our production from operated fields between 2014 and 2016. Production fromnon-operated fields was marketed on our behalf by the operators of those properties.
For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities. For the year ended December 31, 2015, revenues marketed by AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities. For the year ended December 31, 2014, revenues marketed by AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities, and based on revenues excluding hedging activities, one major customer, Murphy Oil Corporation accounted for 10% or more of those revenues, with revenues excluding hedges of $61.2 million. We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available.
NOTE 14 – 401(k) SAVINGS PLAN
Employees of Alta Mesa Services, LP, our wholly owned subsidiary (“Alta Mesa Services”), and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 100% of an employee’s salary deferral contribution up to a maximum of 5% of an employee’s salary, effective January 1, 2016. Matching contributions to the plan were approximately $1,122,000, $710,000, and $683,000 for the years ended December 31, 2016, 2015 and 2014, respectively.
NOTE 15 – SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In
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particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 7.
NOTE 16 – PARTNERS’ CAPITAL (DEFICIT)
Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our sole Class B partner is High Mesa.
On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”). Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our board of directors includes one member nominated by Highbridge, five members nominated by the Class A partners and two members nominated by Bayou City.
Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for reasons of “cause,” which are defined in the partnership agreement. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.
On August 31, 2016, our Class B partner completed the sale of preferred stock toBCE-MESA Holdings, LLC(“BCE-MESA”), a fund managed by Bayou City. In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Amended Partnership Agreement”). The Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner by the Class A partners of their remaining Class A units upon an initial public offering.
In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen, the founder and managing partner of Bayou City, was appointed to the board of managers of our General Partner.
On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City. In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner.
Contribution, Distribution, and Income Allocation: All distributions under the Amended Partnership Agreement shall first be made to holders of Class B units, until certain provisions are met. After such provisions are met, distributions shall then be made to holders of Class A and Class B units pursuant to the distribution formulas set forth in the Amended Partnership Agreement.
The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.
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Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the Amended Partnership Agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.
In connection with the final sale of preferred stock to Bayou City, our Class B partner contributed $300 million from the Bayou City investment to us. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date. The remaining funds are available to be used for general corporate purposes.
As described in Notes 4 and 9, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us on December 31, 2016. High Mesa’s equity contribution was recorded at the contribution date fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.
During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.
We made no distributions for the year ended December 31, 2016. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. For the year ended December 31, 2014, we made distributions of approximately $0.5 million to our founder as discussed in Note 9 and the partners’ share of taxes related to the sale of AME as discussed in Note 4.
NOTE 17 – SUBSIDIARY GUARANTORS
All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors and are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.
NOTE 18 – SUPPLEMENTAL QUARTERLY INFORMATION(Unaudited)
Results of operations by quarter for the year ended December 31, 2016 were:
Quarter Ended | ||||||||||||||||
2016 | March 31 | June 30 | Sept 30 | Dec 31 | ||||||||||||
(in thousands) | ||||||||||||||||
Total operating revenues | $ | 38,167 | $ | 53,823 | $ | 54,532 | $ | 64,186 | ||||||||
Loss from operations(1)(2) | (7,967 | ) | (52,686 | ) | (8,620 | ) | (20,536 | ) | ||||||||
Net loss | $ | (24,157 | ) | $ | (70,327 | ) | $ | (26,567 | ) | $ | (46,870 | ) |
(1) | Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively. |
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(2) | Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016. |
Results of operations by quarter for the year ended December 31, 2015 were:
Quarter Ended | ||||||||||||||||
2015 | March 31 | June 30 | Sept 30 | Dec 31 | ||||||||||||
(in thousands) | ||||||||||||||||
Total operating revenues | $ | 60,542 | $ | 71,755 | $ | 61,344 | $ | 48,325 | ||||||||
Income (loss) from operations(3)(4)(5) | (95,077 | ) | (23,881 | ) | 110,069 | (60,592 | ) | |||||||||
Net income (loss) | $ | (109,211 | ) | $ | (39,509 | ) | $ | 93,079 | $ | (76,152 | ) |
(3) | Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. |
(4) | Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively. |
(5) | Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 2015. |
NOTE 19 – SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)
The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic932-235.
Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.
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Estimated Quantities of Proved Reserves
The following table sets forth our net proved reserves as of December 31, 2016, 2015 and 2014, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.
Oil (MBbls) | Gas (MMcf) | NGL’s (MBbls) | BOE (MBbls) | |||||||||||||
Total Proved Reserves: | ||||||||||||||||
Balance at December 31, 2013 | 32,517 | 132,265 | 5,735 | 60,296 | ||||||||||||
Production | (3,770 | ) | (14,449 | ) | (537 | ) | (6,715 | ) | ||||||||
Purchases in place | 610 | 327 | — | 665 | ||||||||||||
Discoveries and extensions | 13,281 | 28,822 | 4,119 | 22,204 | ||||||||||||
Sales of reserves in place | (6,298 | ) | (35,857 | ) | (949 | ) | (13,223 | ) | ||||||||
Revisions of previous quantity estimates and other | (4,996 | ) | (7,960 | ) | 20 | (6,304 | ) | |||||||||
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Balance at December 31, 2014 | 31,344 | 103,148 | 8,388 | 56,923 | ||||||||||||
Production | (4,203 | ) | (11,900 | ) | (678 | ) | (6,865 | ) | ||||||||
Discoveries and extensions | 12,981 | 58,129 | 7,763 | 30,432 | ||||||||||||
Sales of reserves in place | (6,544 | ) | (8,250 | ) | (748 | ) | (8,667 | ) | ||||||||
Revisions of previous quantity estimates and other | 564 | 14,296 | 3,712 | 6,660 | ||||||||||||
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Balance at December 31, 2015 | 34,142 | 155,423 | 18,437 | 78,483 | ||||||||||||
Production | (4,001 | ) | (13,959 | ) | (956 | ) | (7,284 | ) | ||||||||
Purchases in place(1) | 1,508 | 6,754 | 613 | 3,247 | ||||||||||||
Discoveries and extensions | 29,903 | 154,653 | 14,000 | 69,679 | ||||||||||||
Sales of reserves in place | (73 | ) | (966 | ) | (10 | ) | (244 | ) | ||||||||
Revisions of previous quantity estimates and other | (3,680 | ) | 14,100 | (3,794 | ) | (5,124 | ) | |||||||||
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Balance at December 31, 2016 | 57,799 | 316,005 | 28,290 | 138,757 | ||||||||||||
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Proved Developed Reserves: | ||||||||||||||||
Balance at December 31, 2014 | 15,182 | 63,334 | 4,028 | 29,765 | ||||||||||||
Balance at December 31, 2015 | 14,942 | 71,752 | 6,958 | 33,859 | ||||||||||||
Balance at December 31, 2016 | 16,832 | 93,361 | 7,977 | 40,371 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Balance at December 31, 2014 | 16,162 | 39,814 | 4,360 | 27,158 | ||||||||||||
Balance at December 31, 2015 | 19,200 | 83,671 | 11,479 | 44,624 | ||||||||||||
Balance at December 31, 2016 | 40,967 | 222,644 | 20,313 | 98,386 |
(1) | Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 – Related Party Transactions and Note 16 – Partners’ Capital (Deficit) for further details. |
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Capitalized Costs Relating to Oil and Natural Gas Producing Activities
December 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Capitalized costs: | ||||||||
Proved properties | $ | 1,611,249 | $ | 1,345,482 | ||||
Unproved properties | 116,311 | 127,551 | ||||||
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| |||||
Total | 1,727,560 | 1,473,033 | ||||||
Accumulated depreciation, depletion, amortization and impairment | (1,015,398 | ) | (947,091 | ) | ||||
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| |||||
Net capitalized costs | $ | 712,162 | $ | 525,942 | ||||
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Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Costs incurred during the year: | ||||||||||||
Property acquisition costs | ||||||||||||
Unproved(1) | $ | 66,788 | $ | 74,475 | $ | 33,787 | ||||||
Proved(2) | 68,478 | 2,899 | 7,462 | |||||||||
Exploration | 28,480 | 34,275 | 59,201 | |||||||||
Development(3) | 165,796 | 146,299 | 341,594 | |||||||||
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| |||||||
$ | 329,542 | $ | 257,948 | $ | 442,044 | |||||||
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(1) | Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. |
(2) | Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $65.7 million. |
(3) | Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. |
Standardized Measure of Discounted Future Net Cash Flows
The information that follows has been developed pursuant to ASC932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Future cash inflows as of December 31, 2016, 2015 and 2014 were calculated using anun-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in
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consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.
The following table sets forth the components of the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014:
At December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Future cash flows | $ | 3,547,130 | $ | 2,395,128 | $ | 3,737,412 | ||||||
Future production costs | (1,811,683 | ) | (860,600 | ) | (991,149 | ) | ||||||
Future development costs | (709,738 | ) | (403,953 | ) | (450,659 | ) | ||||||
Future taxes on income | — | — | — | |||||||||
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| |||||||
Future net cash flows | 1,025,709 | 1,130,575 | 2,295,604 | |||||||||
Discount to present value at 10 percent per annum | (467,101 | ) | (500,979 | ) | (877,558 | ) | ||||||
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Standardized measure of discounted future net cash flows | $ | 558,608 | $ | 629,596 | $ | 1,418,046 | ||||||
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| |||||||
Base price for crude oil, per Bbl, in the above computation was: | $ | 42.75 | $ | 50.28 | $ | 94.99 | ||||||
Base price for natural gas, per Mcf, in the above computation was: | $ | 2.49 | $ | 2.58 | $ | 4.35 |
No consideration was given to the Company’s hedged transactions. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash flows:
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(in thousands) | ||||||||||||
Balance at beginning of year | $ | 629,596 | $ | 1,418,046 | $ | 1,406,274 | ||||||
Sales of oil and natural gas, net of production costs | (124,610 | ) | (147,906 | ) | (320,130 | ) | ||||||
Changes in sales and transfer prices, net of production costs | (324,638 | ) | (823,073 | ) | (153,770 | ) | ||||||
Revisions of previous quantity estimates | (35,972 | ) | 53,101 | (477,377 | ) | |||||||
Purchases ofreserves-in-place | 40,611 | — | 21,633 | |||||||||
Sales ofreserves-in-place | 2,345 | (244,251 | ) | (107,414 | ) | |||||||
Current year discoveries and extensions | 356,631 | 260,078 | 701,820 | |||||||||
Changes in estimated future development costs | 849 | 4,376 | 2,591 | |||||||||
Development costs incurred during the year | 8,363 | 42,420 | 161,357 | |||||||||
Accretion of discount | 62,960 | 141,805 | 140,627 | |||||||||
Net change in income taxes | — | — | — | |||||||||
Change in production rate (timing) and other | (57,527 | ) | (75,000 | ) | 42,435 | |||||||
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Net change | (70,988 | ) | (788,450 | ) | 11,772 | |||||||
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Balance at end of year | $ | 558,608 | $ | 629,596 | $ | 1,418,046 | ||||||
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KINGFISHER MIDSTREAM, LLC
SEPTEMBER 30, 2017 AND DECEMBER 31, 2016
(Unaudited)
2017 | 2016 | |||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 11,721,600 | $ | 40,986,822 | ||||
Accounts receivable | 5,230,798 | 137,569 | ||||||
Accounts receivable from affiliates | 10,028,222 | 6,237,306 | ||||||
Prepaid expenses | 780,166 | — | ||||||
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| |||||
TOTAL CURRENT ASSETS | 27,760,786 | 47,361,697 | ||||||
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| |||||
NONCURRENT ASSETS | ||||||||
Land | 587,377 | 566,822 | ||||||
Vehicles, net | 385,439 | 51,312 | ||||||
Property, plant, and equipment, net | 158,363,491 | 92,290,775 | ||||||
Construction work in progress | 68,859,096 | 79,938,738 | ||||||
Accounts receivable | 225,000 | — | ||||||
Deposits | 146,689 | — | ||||||
Deferred loan costs, net | 3,056,945 | — | ||||||
�� |
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| ||||
TOTAL LONG TERM ASSETS | 231,624,037 | 176,847,647 | ||||||
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TOTAL ASSETS | $ | 259,384,823 | $ | 224,209,344 | ||||
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LIABILITIES AND MEMBERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 3,558,533 | $ | 10,333,283 | ||||
Accounts payable to affiliates | 6,569,476 | 2,041,137 | ||||||
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TOTAL CURRENT LIABILITIES | 10,128,009 | 12,374,420 | ||||||
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TOTAL LIABILITIES | 10,128,009 | 12,374,420 | ||||||
TOTAL MEMBERS’ EQUITY | 249,256,814 | 211,834,924 | ||||||
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TOTAL LIABILITIES AND MEMBERS’ EQUITY | $ | 259,384,823 | $ | 224,209,344 | ||||
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KINGFISHER MIDSTREAM, LLC
FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2017 AND 2016
(Unaudited)
2017 | 2016 | |||||||
Operating Revenues: | ||||||||
Natural gas, NGLs and condensate revenue | $ | 62,428,889 | $ | — | ||||
Gathering, processing, compression and other fee revenue | 29,043,497 | 6,367,208 | ||||||
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Total operating revenues | 91,472,386 | 6,367,208 | ||||||
Operating Expenses: | ||||||||
Cost of natural gas and NGLs | 64,539,296 | 1,906,823 | ||||||
Operation and maintenance | 4,531,749 | 1,722,191 | ||||||
General and administrative | 5,508,870 | 2,059,046 | ||||||
Depreciation and amortization | 6,892,706 | 2,200,611 | ||||||
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| |||||
Total operating expenses | 81,472,621 | 7,888,671 | ||||||
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| |||||
Operating income (loss) | 9,999,765 | (1,521,463 | ) | |||||
Interest expense | 132,537 | — | ||||||
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| |||||
Net income (loss) | $ | 9,867,228 | $ | (1,521,463 | ) | |||
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KINGFISHER MIDSTREAM, LLC
FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2017 AND 2016
(Unaudited)
2017 | 2016 | |||||||
Balance at Beginning of period | $ | 211,834,924 | $ | 106,967,416 | ||||
Contributions | 45,000,000 | 77,600,000 | ||||||
Distributions | (17,445,338 | ) | (10,033,070 | ) | ||||
Net income (loss) | 9,867,228 | (1,521,463 | ) | |||||
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| |||||
Balance at End of period | $ | 249,256,814 | $ | 173,012,883 | ||||
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KINGFISHER MIDSTREAM, LLC
FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2017 AND 2016
(Unaudited)
2017 | 2016 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | 9,867,228 | $ | (1,521,463 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||
Depreciation and amortization | 6,892,706 | 2,200,611 | ||||||
Amortization of deferred loan costs | 132,537 | — | ||||||
Changes in operating assets and liabilities: | ||||||||
Increase in accounts receivable | (5,318,228 | ) | — | |||||
Increase in accounts receivable from affiliates | (1,761,796 | ) | (5,330,882 | ) | ||||
Increase in prepaid expenses | (780,166 | ) | — | |||||
Decrease in accounts payable | (6,774,750 | ) | (2,235,693 | ) | ||||
Increase in accounts payable to affiliates | 4,528,338 | 254,928 | ||||||
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| |||||
Net cash provided by (used in) operating activities | 6,785,869 | (6,632,499 | ) | |||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Increase in construction in progress | (57,863,989 | ) | (92,543,039 | ) | ||||
Purchase of land | (20,555 | ) | (135,587 | ) | ||||
Capital expenditures for property and equipment | (355,918 | ) | — | |||||
Increase in accounts receivable from affiliate | (2,029,120 | ) | — | |||||
Increase in deposits | (146,689 | ) | — | |||||
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Net cash used in investing activities | (60,416,271 | ) | (92,678,626 | ) | ||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Payments for deferred loan costs | (3,189,482 | ) | — | |||||
Contributions | 45,000,000 | 77,600,000 | ||||||
Distributions | (17,445,338 | ) | (10,033,070 | ) | ||||
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| |||||
Net cash provided by financing activities | 24,365,180 | 67,566,930 | ||||||
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| |||||
Net decrease in cash and cash equivalents | (29,265,222 | ) | (31,744,195 | ) | ||||
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| |||||
Cash and cash equivalents, beginning of period | 40,986,822 | 60,430,115 | ||||||
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| |||||
Cash and cash equivalents, end of period | $ | 11,721,600 | $ | 28,685,920 | ||||
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SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||
Cash paid during the year for interest | $ | — | $ | — | ||||
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Cash paid during the year for taxes | $ | — | $ | — | ||||
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
(Unaudited)
NOTE 1: ORGANIZATION
Kingfisher Midstream, LLC (the “Company”) is a Delaware limited liability company formed on January 30, 2015 for the purpose of acquiring, developing and operating midstream oil and gas assets. Midstream operations are primarily comprised of crude gathering, gas gathering and processing and marketing of products.
Limited liability companies (“LLCs”) are formed in accordance with the laws of the state in which they are organized. LLCs are generally an unincorporated association of single or multiple members.
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from the estimates that are used.
Cash and Cash Equivalents
Investments in highly-liquid securities with original maturities of three months or less are considered to be cash equivalents. As of September 30, 2017 and 2016, respectively, the Company maintained cash deposits with financial institutions in excess of the federally insured limits. The Company believes the credit risk in these deposits is minimal.
Accounts Receivable
Accounts receivable represent valid claims against customers for services rendered. Management evaluates the adequacy of the allowance for doubtful accounts based on a periodic review of individual accounts. The primary factors considered in determining the amount of the allowance are collection history, the aging of the accounts, and other specific information known to management that may affect collectability. As of September 30, 2017 and 2016 management has determined that no allowance for doubtful accounts is necessary.
Revenue Recognition
Revenues are primarily generated by charging fees on a per unit basis for gathering crude oil and natural gas and processing natural gas. The Company recognizes revenue when services have been rendered, the prices are fixed or determinable and collectability is reasonably assured. In addition, revenue from sales of crude oil, natural gas and NGLs is recognized when title passes to the customer, which is when risk of ownership passes to the customer and physical delivery occurs, the price of the product is fixed or determinable and collectability is reasonably assured.
Income Taxes
As a Limited Liability Company, the Company is not liable for federal income taxes. Income and losses of the Company are reported in the income tax return of each member. Accordingly, there is no provision for federal income taxes in the accompanying financial statements.
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
(Unaudited)
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES—(Continued)
The Company follows the provisions of theIncome Taxes Topic of the FASB ASC related to uncertain tax positions. The Company recognized no liability for unrecognized tax benefits and has no tax position at September 30, 2017 and 2016, for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. The Company recognizes interest and penalties related to uncertain tax positions in the statement of operations as interest expense and general and administrative expense, respectively. The Company is open to audit under the statute of limitations from the date of inception January 30, 2015 and beyond.
Property and Equipment
Property, plant and equipment are recorded at cost, including improvements that substantially add to the productive capacity or extend the useful life of the related asset, less accumulated depreciation. Maintenance, repairs and minor renewals are expensed as incurred. During 2017 and 2016, portions of the gas and crude gathering system and processing plant were placed in service as completed and operational. Depreciation is computed using the straight-line method over the following useful lives:
Vehicles | 5 years | |
Property, plant and equipment | 3-20 years |
Asset Retirement Obligations
The Company records a liability for asset retirement obligations in the period the obligation is incurred and when management can make a reasonable estimate of the fair value of the obligation. If a reasonable estimate cannot be made at the time the liability is incurred, the Company records the liability when sufficient information is available to estimate the fair value. The Company has legal obligations in the form ofright-of-way agreements, which requires the Company to remove certain assets upon termination of the agreement. However, the Company intends to extend indefinitely theseright-of-way agreements that include asset retirement obligations. As of September 30, 2017 and 2016, the Company did not have assets that were legally restricted for purposes of settling asset retirement obligations.
Organizational Expense
The Company expenses organizational andstart-up costs as incurred.
Deferred Loan Costs
Costs related to originating or amending the Company’s loans are amortized over the life of the loan. For the periods ended September 30, 2017 and 2016, the Company incurred $132,537 and $0 of amortization expense reported as interest expense, respectively. Deferred loan costs are presented as an asset, as they related to a line-of-credit arrangement.
NOTE 3: MEMBERS’ EQUITY
On August 31, 2015, the Company entered into an amended and restated limited liability company agreement with certain investors. At September 30, 2017, 4,000,000 and 147,100,000 of class A units and class B units are issued and outstanding, respectively. The terms of the units are governed by the LLC Agreement.
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
(Unaudited)
NOTE 3: MEMBERS’ EQUITY—(Continued)
In accordance with the LLC Agreement, income and losses of the Company are allocated and charged in accordance with terms as set forth in the LLC Agreement.
On August 4, 2017, the members agreed to contribute their respective limited liability company interests in Kingfisher Midstream, LLC to KFM Holdco, LLC (“Holdco”), a Delaware limited liability company, in exchange for an equal number and class of units. As a result, “Holdco” is the sole member of the Company.
NOTE 4: PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment as of September 30, 2017 and 2016 consisted of the following:
2017 | 2016 | |||||||
Land | $ | 587,377 | $ | 550,761 | ||||
Vehicles, net | 420,058 | 64,140 | ||||||
Property, plant, and equipment | 168,973,456 | 97,504,382 | ||||||
Construction work in progress | 68,859,096 | 44,485,018 | ||||||
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| |||||
Total property, plant and equipment | 238,839,987 | 142,604,301 | ||||||
Accumulated depreciation | (10,644,584 | ) | (2,200,611 | ) | ||||
|
|
|
| |||||
Net property, plant and equipment | $ | 228,195,403 | $ | 140,403,690 | ||||
|
|
|
|
As of September 30, 2017, the Company’s construction work in progress that has not been placed in service has not been depreciated. For the periods ended September 30, 2017 and 2016, respectively, the Company had depreciation expense of $6,892,706 and $2,200,611.
NOTE 5: RELATED PARTY TRANSACTIONS
The Company shares overhead expenses with Asset Risk Management, LLC including rent, salaries, and information technology support through an Operating and Construction Management Agreement dated August 31, 2015 and amended from time to time. As of September 30, 2017 and 2016, respectively, the Company had a net payable of $844,364 and $575,435. Total reimbursed overhead expenses for the nine months ending September 30, 2017 and 2016, respectively, were $2,221,990 and $2,337,196.
During 2017, the Company invoiced ARM Energy Management, LLC (a related party) for sales marketed on behalf of Kingfisher producers. As of September 30, 2017 and 2016, respectively, the Company had a net receivable of $4,251,780 and $5,330,882.
The Company receives and generates invoices from and to Oklahoma Energy Acquisitions for the purchase and sale of hydrocarbons and providing midstream services. As of September 30, 2017 and 2016, respectively, the Company had a net payable of $1,980,491 and $0.
The Company previously made a deposit of $10,065,000 to ONEOK Gas Transportation, LLC that was funded by Alta Mesa Services, LP (a related party) for firm transportation capacity. Effective September 1, 2017, the Company assigned the agreement to Alta Mesa Holdings, LP.
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
(Unaudited)
NOTE 5: RELATED PARTY TRANSACTIONS—(Continued)
During 2017, Holdco incurred transaction expenses related to the Kingfisher Midstream, LLC Contribution Agreement as reference in Note 8, Contribution Agreement. The Company has paid these expenses on behalf of Holdco and expects to be reimbursed at the close of the transaction with Silver Run Acquisition Corporation II. As of September 30, 2017 and 2016, respectively, the Company had a receivable of $2,029,120 and $0.
NOTE 6: DEBT
The Company entered a new $200.0 million revolving credit facility with a syndicate of lenders on August 8, 2017. The credit facility has a four-year term, with repayment due at maturity on August 8, 2021. ABN AMRO Capital USA LLC acts as agent, initial letter of credit issuer, bookrunner and lead arranger. The credit facility includes a letter of credit sublimit of $20.0 million for the issuance of letters of credit. The Company has the option to increase its borrowing capacity under its revolving credit facility by an amount not to exceed $50.0 million (for a total commitment of $250.0 million subject to certain conditions). The Company’s revolving credit facility will be available to fund capital expenditures, working capital, general corporate purposes and to finance approved acquisitions.
The credit facility is secured by substantially all of our real property interests, pledged equity and intangibles. The applicable margins are dependent upon the Company’s leverage ratio, with the highest margins for Eurodollar loans and base rate loans being 3.25% and 2.25%, respectively. The revolving credit facility is subject to commitment fees ranging from 0.50% to 0.375% based on the leverage grid. The revolving credit facility is subject to customary affirmative and negative covenants and events of default relating to the Company.
As of September 30, 2017, the Company has not borrowed on the credit facility.
NOTE 7: COMMITMENTS AND CONTINGENCIES
Commitments
The Company has entered into certain firm transportation contracts that extend through 2036. Future minimum commitments related to these contracts for the periods ending September 30 are as follows:
Year | Amount | |||
2018 | $ | 9,796,914 | ||
2019 | 9,773,853 | |||
2020 | 6,113,067 | |||
2021 | 6,097,567 | |||
2022 | 5,950,878 | |||
Thereafter | 76,903,250 | |||
|
| |||
Total | $ | 114,635,529 | ||
|
|
Legal Matters
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, a wholly owned subsidiary of Alta Mesa (“OEA”), and eight other entities, including the Company. Mustang alleges that (1) Mustang is a party to
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
(Unaudited)
NOTE 7: COMMITMENTS AND CONTINGENCIES—(Continued)
gas purchase agreements with OEA containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) OEA, in concert with the other defendants, has wrongfully diverted gas sales to Kingfisher in contravention of these agreements.
Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against OEA only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants, including Kingfisher. While the Company may incur costs or losses in connection with this litigation, the Company has not accrued a loss contingency because it is currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. The Company believes that the allegations contained in this lawsuit are without merit and intends to vigorously defend itself.
From time to time, the Company is party to other lawsuits arising in the ordinary course of its business. The Company cannot predict the outcome of any such lawsuits with certainty, but the Company’s management believes it is remote that pending or threatened legal matters will have a material adverse impact on the Company’s financial condition.
NOTE 8: CONTRIBUTION AGREEMENT
On August 16, 2017, Holdco and the Company entered into a Contribution Agreement (the “CA”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”). The members of Holdco were comprised of ARM-M I, LLC, HMS Kingfisher Holdco, LLC and various funds managed by HPS Investment Partners, LLC (collectively, the “Members”). Pursuant to the CA, SRII will acquire from Holdco all of its membership interest in the Company. In exchange, Holdco will receive: (i) $800 million in cash; (ii) 55,000,000 common units of SRII Opco, LP; and (iii) up to $200 million in earn-out consideration in the form of common units, subject to certain conditions.
The CA contains customary representations and warranties. The closing of the CA is subject to: (i) approval of the SRII stockholders; (ii) the simultaneous closing of the contribution agreement by and among High Mesa Holdings, LP and affiliates and the equity owners party thereto pursuant to which SRII will acquire 100% of the limited partner interest, 100% of the economic interests and 90% of the voting interests in the affiliate’s General Partner.
NOTE 9: SUBSEQUENT EVENTS
Management has evaluated subsequent events from October 1, 2017 through November 20, 2017, which is the date the financial statements were available to be issued.
As of November 20, 2017, the Company had $30.0 million in debt outstanding, with $54.6 million of availability.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Members of Kingfisher Midstream, LLC
We have audited the accompanying balance sheets of Kingfisher Midstream, LLC as of December 31, 2016 and 2015, and the related statements of operations, members’ equity, and cash flows for the year ended December 31, 2016 and 2015. Kingfisher Midstream, LLC’s management is responsible for these financial statements. 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. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Kingfisher Midstream, LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years ended December 31, 2016 and 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ EEPB, P.C.
Houston, Texas
October 26, 2017
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KINGFISHER MIDSTREAM, LLC
DECEMBER 31, 2016 AND 2015
2016 | 2015 | |||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 40,986,822 | $ | 60,430,115 | ||||
Accounts receivable | 137,569 | — | ||||||
Accounts receivable from affiliates | 6,237,306 | — | ||||||
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TOTAL CURRENT ASSETS | 47,361,697 | 60,430,115 | ||||||
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NONCURRENT ASSETS | ||||||||
Land | 566,822 | 415,174 | ||||||
Vehicles, net | 51,312 | 64,140 | ||||||
Property, plant, and equipment, net | 96,290,775 | — | ||||||
Construction work in progress | 79,938,738 | 49,446,361 | ||||||
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Deferred loan costs, net | — | — | ||||||
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TOTAL NONCURRENT ASSETS | 176,847,647 | 49,925,675 | ||||||
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TOTAL ASSETS | $ | 224,209,344 | $ | 110,355,790 | ||||
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LIABILITIES AND MEMBERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 10,333,283 | $ | 3,067,868 | ||||
Payable to affiliates | 2,041,137 | 320,506 | ||||||
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TOTAL CURRENT LIABILITIES | 12,374,420 | 3,388,374 | ||||||
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MEMBERS’ EQUITY | 211,834,924 | 106,967,416 | ||||||
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TOTAL LIABILITIES AND MEMBERS’ EQUITY | $ | 224,209,344 | $ | 110,355,790 | ||||
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KINGFISHER MIDSTREAM, LLC
FOR THE YEAR ENDED DECEMBER 31, 2016 AND THE PERIOD FROM INCEPTION
(JANUARY 30, 2015) THROUGH DECEMBER 31, 2015
2016 | 2015 | |||||||
REVENUES | $ | 15,177,892 | $ | — | ||||
OPERATING EXPENSES | ||||||||
Cost of sales | 4,014,150 | — | ||||||
Operation expenses | 3,416,911 | — | ||||||
Depreciation | 3,751,878 | — | ||||||
Salaries and benefits | 2,013,884 | 844,222 | ||||||
Professional fees | 678,519 | 427,955 | ||||||
Travel and entertainment | 372,491 | 55,253 | ||||||
Rent | 90,000 | 30,000 | ||||||
Other general and administrative | 622,877 | 79,420 | ||||||
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TOTAL OPERATING EXPENSES | 14,960,710 | 1,436,850 | ||||||
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NET INCOME (LOSS) | $ | 217,182 | $ | (1,436,850 | ) | |||
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KINGFISHER MIDSTREAM, LLC
FOR THE YEAR ENDED DECEMBER 31, 2016 AND THE PERIOD FROM INCEPTION
(JANUARY 30, 2015) THROUGH DECEMBER 31, 2015
Total | ||||
Balance at January 30, 2015 (Inception) | $ | — | ||
Contributions | 112,300,000 | |||
Distributions | (3,895,734 | ) | ||
Net loss | (1,436,850 | ) | ||
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| |||
Balance at December 31, 2015 | 106,967,416 | |||
Contributions | 115,980,000 | |||
Distributions | (11,329,674 | ) | ||
Net income | 217,182 | |||
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Balance at December 31, 2016 | $ | 211,834,924 | ||
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KINGFISHER MIDSTREAM, LLC
FOR THE YEAR ENDED DECEMBER 31, 2016 AND THE PERIOD FROM INCEPTION
(JANUARY 30, 2015) THROUGH DECEMBER 31, 2015
2016 | 2015 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Net income (loss) | $ | 217,182 | $ | (1,436,850 | ) | |||
Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
Depreciation and amortization | 3,751,878 | — | ||||||
Changes in operating assets and liabilities: | ||||||||
Decrease in accounts receivable | (137,569 | ) | — | |||||
Increase in accounts receivable from affiliates | (6,237,306 | ) | — | |||||
Increase in accounts payable | 51,598 | — | ||||||
Increase in accrued expenses | 1,720,631 | 320,506 | ||||||
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NET CASH USED IN OPERATING ACTIVITIES | (633,586 | ) | (1,116,344 | ) | ||||
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CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Increase in construction in progress | (123,221,354 | ) | (46,378,493 | ) | ||||
Purchase of property, plant and equipment | (238,679 | ) | (479,314 | ) | ||||
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NET CASH USED IN INVESTING ACTIVITIES | (123,460,033 | ) | (46,857,807 | ) | ||||
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CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Contributions | 115,980,000 | 112,300,000 | ||||||
Distributions | (11,329,674 | ) | (3,895,734 | ) | ||||
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NET CASH PROVIDED FROM FINANCING ACTIVITIES | 104,650,326 | 108,404,266 | ||||||
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (19,443,293 | ) | 60,430,115 | |||||
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CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 60,430,115 | — | ||||||
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CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 40,986,822 | $ | 60,430,115 | ||||
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SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||
Cash paid during the year for interest | $ | — | $ | — | ||||
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Cash paid during the year for taxes | $ | — | $ | — | ||||
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SUPPLEMENTAL NONCASH INVESTING ACTIVITY | ||||||||
Construction in progress in accounts payable | $ | 7,213,817 | $ | 3,067,868 | ||||
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION
Kingfisher Midstream, LLC (the “Company”) is a Delaware limited liability company formed on January 30, 2015 for the purpose of acquiring, developing and operating midstream oil and gas assets. Midstream operations are primarily comprised of crude gathering, gas gathering and processing and marketing of products.
Limited liability companies (“LLCs”) are formed in accordance with the laws of the state in which they are organized. LLCs are generally an unincorporated association of single or multiple members.
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from the estimates that are used.
Cash and Cash Equivalents
Investments in highly-liquid securities with original maturities of three months or less are considered to be cash equivalents. As of and during the years ended December 31, 2016 and 2015, the Company maintained cash deposits with financial institutions in excess of the federally insured limits. The Company believes the credit risk in these deposits is minimal.
Accounts Receivable
Accounts receivable represent valid claims against customers for services rendered. Management evaluates the adequacy of the allowance for doubtful accounts based on a periodic review of individual accounts. The primary factors considered in determining the amount of the allowance are collection history, the aging of the accounts, and other specific information known to management that may affect collectability. As of December 31, 2016 and 2015 management has determined that no allowance for doubtful accounts is necessary.
Revenue Recognition
Revenues are primarily generated by charging fees on a per unit basis for gathering crude oil and natural gas and processing natural gas. The Company recognizes revenue when services have been rendered, the prices are fixed or determinable and collectability is reasonably assured. In addition, revenue from sales of crude oil, natural gas and NGLs is recognized when title passes to the customer, which is when risk of ownership passes to the customer and physical delivery occurs, the price of the product is fixed or determinable and collectability is reasonably assured.
Income Taxes
As a Limited Liability Company, the Company is not liable for federal income taxes. Income and losses of the Company are reported in the income tax return of each member. Accordingly, there is no provision for federal income taxes in the accompanying financial statements.
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES—(Continued)
The Company follows the provisions of theIncome Taxes Topic of the FASB ASC related to uncertain tax positions. The Company recognized no liability for unrecognized tax benefits and has no tax position at December 31, 2016 and 2015, for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. The Company recognizes interest and penalties related to uncertain tax positions in the statement of operations as interest expense and general and administrative expense, respectively. The Company is open to audit under the statute of limitations from the date of inception January 30, 2015 and beyond.
Property and Equipment
Property, plant and equipment are recorded at cost, including improvements that substantially add to the productive capacity or extend the useful life of the related asset, less accumulated depreciation. Maintenance, repairs and minor renewals are expensed as incurred. During 2016, portions of the gas and crude gathering system and processing plant were placed in service as completed and operational. Depreciation is computed using the straight-line method over the following useful lives:
Vehicles | 5 years | |
Property, plant and equipment | 3-20 years |
Asset Retirement Obligations
The Company records a liability for asset retirement obligations in the period the obligation is incurred and when management can make a reasonable estimate of the fair value of the obligation. If a reasonable estimate cannot be made at the time the liability is incurred, the Company records the liability when sufficient information is available to estimate the fair value. The Company has legal obligations in the form ofright-of-way agreements, which requires the Company to remove certain assets upon termination of the agreement. However, the Company intends to extend indefinitely theseright-of-way agreements that include asset retirement obligations. As of December 31, 2016 and 2015, the Company did not have assets that were legally restricted for purposes of settling asset retirement obligations.
Organizational Expense
The Company expenses organizational andstart-up costs as incurred.
NOTE 3: MEMBERS’ EQUITY
On August 31, 2015, the Company entered into an amended and restated limited liability company agreement with certain investors. At December 31, 2016, 4,000,000 and 147,100,000 of class A units and class B units are issued and outstanding, respectively. The terms of the units are governed by the LLC Agreement.
In accordance with the LLC Agreement, income and losses of the Company are allocated and charged in accordance with terms as set forth in the LLC Agreement.
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
NOTE 4: PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment as of December 31, 2016 and 2015 consisted of the following:
2016 | 2015 | |||||||
Land | $ | 566,822 | $ | 415,174 | ||||
Vehicles | 64,140 | 64,140 | ||||||
Property, plant and equipment | 100,029,825 | — | ||||||
Construction work in progress | 79,938,738 | 49,446,361 | ||||||
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Total property, plant and equipment | 180,599,525 | 49,925,675 | ||||||
Accumulated depreciation | (3,751,878 | ) | — | |||||
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Net property, plant and equipment | $ | 176,847,647 | $ | 49,925,675 | ||||
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As of December 31, 2016, the Company’s construction work in progress that has not been placed in service has not been depreciated. For the years ended December 31, 2016 and 2015, the Company had depreciation expense of $3,751,878 and $0, respectively.
NOTE 5: RELATED PARTY TRANSACTIONS
The Company shares overhead expenses with Asset Risk Management, LLC including rent, salaries, and I.T. support through an Operating and Construction Management Agreement dated August 31, 2015 and amended from time to time. As of December 31, 2016 and 2015, respectively, the Company had a net payable of $311,820 and $320,506. Total reimbursed overhead expenses for the year ended December 31, 2016 were $4,279,165.
During 2016, the Company charged gathering, processing and other fees to related parties. As of December 31, 2016, the Company had a net receivable of $6,237,306 related to these charges. The Company also received funds from a third party that are to be paid to a related party. As of December 31, 2016 the amount of funds is a net payable of $1,729,317.
NOTE 6: COMMITMENTS AND CONTINGENCIES
Commitments
The Company has entered into certain firm transportation contracts that extend through 2036. Future minimum commitments related to these contracts as of December 31, 2016, are as follows:
Year | Amount | |||
2017 | $ | 8,318,333 | ||
2018 | 10,971,629 | |||
2019 | 9,860,920 | |||
2020 | 7,443,867 | |||
2021 | 7,423,528 | |||
Thereafter | 91,735,758 | |||
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Total | $ | 135,754,035 | ||
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Legal Matters
From time to time, the Company is involved in various claims and lawsuits, both for and against the Company, arising in the normal course of business. Management believes that any financial responsibility
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KINGFISHER MIDSTREAM, LLC
NOTES TO THE FINANCIAL STATEMENTS
NOTE 6: COMMITMENTS AND CONTINGENCIES—(Continued)
that may be incurred in settlement of such claims and lawsuits would not be material to the Company’s financial statements.
NOTE 7: SUBSEQUENT EVENTS
Management has evaluated subsequent events from January 1, 2017 through October 26, 2017, which is the date the financial statements were available to be issued.
Equity Contribution
In May 2017, the Company received an equity contribution of $45 million.
Kingfisher Contribution Agreement
On August 16, 2017, KFM Holdco, LLC (“Holdco” or “Contributor”) and the Company entered into a Contribution Agreement (the “CA”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”). The members of Holdco were comprised of ARM-M I, LLC, HMS Kingfisher Holdco, LLC and various funds managed by HPS Investment Partners, LLC (collectively, the “Members”). Pursuant to the CA, SRII will acquire from Holdco all of its membership interest in the Company. In exchange, Holdco will receive: (i) $800 million in cash; (ii) 55,000,000 common units of SRII Opco, LP; and (iii) up to $200 million in earn-out consideration in the form of common units, subject to certain conditions.
The CA contains customary representations and warranties. The closing of the CA is subject to: (i) approval of the SRII stockholders; (ii) the simultaneous closing of the contribution agreement by and among High Mesa Holdings, LP and affiliates and the equity owners party thereto pursuant to which SRII will acquire 100% of the limited partner interest, 100% of the economic interests and 90% of the voting interests in the affiliate’s General Partner.
ABN AMRO Capital USA LLC Credit Agreement
The Company entered a new $200 million revolving credit facility with a syndicate of lenders on August 8, 2017. The facility has a four-year term. ABN AMRO Capital USA LLC acts as agent, initial letter of credit issuer, bookrunner and lead arranger. The credit facility includes a letter of credit sublimit of $20 million for the issuance of letters of credit. The Company has the option to increase its borrowing capacity under its revolving credit facility by an amount not to exceed $50 million (for a total commitment of $250 million) subject to certain conditions. The Company’s revolving credit facility will be available to fund capital expenditures, working capital, general corporate purposes and to finance approved acquisitions. As of October 26, 2017, the Company had $30.0 million in debt outstanding, with $54.6 million of availability.
The applicable margins are dependent upon the Company’s leverage ratio, with the highest margins for Eurodollar loans and base rate loans being 3.25% and 2.25%, respectively. The revolving credit facility is subject to commitment fees ranging from 0.50% to 0.375% based on the leverage grid. The revolving credit facility is subject to customary affirmative and negative covenants and events of default relating to the Company.
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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED
FINANCIAL INFORMATION OF SILVER RUN ACQUISITION CORPORATION II
The unaudited pro forma condensed consolidated combined statements of operations of Silver Run for the nine months ended September 30, 2017 and for the year ended December 31, 2016 combine the historical statements of operations of Silver Run, the historical consolidated statements of operations of Alta Mesa and the historical statements of operations of Kingfisher, giving effect to the following transactions (for purposes of this section, collectively, the “Transactions”) as if they had been consummated on January 1, 2016, the beginning of the earliest period presented:
• | the acquisition by Silver Run from the Alta Mesa Contributor of (i) all of the limited partner interests in Alta Mesa held by the Alta Mesa Contributor and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, the sole general partner of Alta Mesa, pursuant to the Alta Mesa Contribution Agreement, in exchange for the issuance by SRII Opco at Closing of 138,402,398 SRII Opco Common Units to the Alta Mesa Contributor. In addition, for a period of seven years following the Closing, the Alta Mesa Contributor will be entitled to receive an aggregate of up to $800 million inearn-out consideration to be paid in the form of SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) if the20-day volume-weighted average price (the“20-Day VWAP”) of the Class A Common Stock equals or exceeds specified prices; |
• | the acquisition by Silver Run of 100% of the outstanding membership interests in Kingfisher, pursuant to the Kingfisher Contribution Agreement in exchange for (x) the payment by Silver Run at Closing of $814.8 million in cash to the Kingfisher Contributor and (y) the issuance by SRII Opco at Closing of 55,000,000 SRII Opco Common Units to the Kingfisher Contributor. In addition, for a period of seven years following the Closing, the Kingfisher Contributor will be entitled to receive an aggregate of up to $200 million inearn-out consideration to be paid in the form of SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) if the20-Day VWAP of the Class A Common Stock equals or exceeds specified prices; |
• | the acquisition by Silver Run of all of the limited partner interests in Alta Mesa held by the Riverstone Contributor, pursuant to the Riverstone Contribution Agreement in exchange for the issuance by SRII Opco at Closing of 20,000,000 SRII Opco Common Units to the Riverstone Contributor; |
• | the conversion of 25,875,000 shares of Class B Common Stock into 25,875,000 shares of Class A Common Stock, in connection with the Closing; |
• | the issuance by Silver Run of a number of shares of Class C Common Stock to the Contributors equal to the number of SRII Opco Common Units issued to such Contributors in connection with the Closing; |
• | the issuance by Silver Run of one share of Series A Preferred Stock to each of Bayou City, HPS and AM Equity Holdings, LP in connection with the Closing; |
• | the issuance by Silver Run of one share of Series B Preferred Stock to the Riverstone Contributor in connection with the Closing; |
• | the issuance and sale by Silver Run of 40,000,000 shares of Class A Common Stock and 13,333,333 warrants to purchase shares of Class A Common Stock, for an aggregate purchase price of $400 million, to Fund VI Holdings pursuant to the terms of the Forward Purchase Agreement; |
• | the redemption by Silver Run of 3,270 shares of Class A Common Stock held by public stockholders in connection with the Business Combination as more fully described below; |
• | the exchange of certain founder notes of Alta Mesa’s subsidiaries (the “Alta Mesa Founder Notes”) for equity interest of the Alta Mesa Contributor prior to Closing pursuant to the Alta Mesa Contribution Agreement; and |
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• | the sale of Weeks Island by Alta Mesa and disposition by Alta Mesa of its remaining non-STACK assets and operations as contemplated by the Alta Mesa Contribution Agreement (the “Alta Mesa non-STACK Assets Divestiture”). |
Additionally, the unaudited pro forma condensed consolidated combined statement of operations of Silver Run for the year ended December 31, 2016 gives effect to the following: (i) the related revenue and expenses from the interests in 24 producing wells (the “Alta Mesa JV Wells”) not owned by Alta Mesa that were drilled under the joint development agreement and purchased by High Mesa from BCE-STACK Development LLC (“BCE”) and contributed to Alta Mesa on December 31, 2016 (the “Alta Mesa JV Wells Contribution”) and (ii) the issuance of Alta Mesa’s $500 million aggregate principal amount of 7.875% senior notes due 2024 (the “2024 Notes”), the repayment of Alta Mesa’s $450 million aggregate principal amount of 9.625% senior notes due 2018 (the “2018 Notes”), and the repayment in full of Alta Mesa’s $125 million senior secured term loan facility on November 10, 2016 (the “2016 Refinancing”). Although the Alta Mesa JV Wells Contribution is not considered significant to Alta Mesa under SEC rules as it did not meet the three criteria of the significance test set forth in Article 11 of Regulation S-X, Silver Run’s management believes the prospective results of the Alta Mesa JV Wells will have a continuing impact on Silver Run’s results of operations such that the pro forma financial statements would be misleading without giving effect to this transaction.
The unaudited pro forma condensed consolidated combined balance sheet of Silver Run as of September 30, 2017 combines the historical condensed balance sheet of Silver Run, the historical condensed consolidated balance sheet of Alta Mesa and the historical condensed balance sheet of Kingfisher, giving effect to the Transactions (other than the Alta Mesa JV Wells Contribution and the 2016 Refinancing) as if they had been consummated on September 30, 2017. The contribution date fair value of the Alta Mesa JV Wells and the 2016 Refinancing are reflected in Alta Mesa’s historical consolidated balance sheet as of September 30, 2017, and, therefore, the unaudited pro forma condensed consolidated combined balance sheet information of Silver Run does not give effect to the Alta Mesa JV Wells Contribution and the 2016 Refinancing.
The historical consolidated financial statements have been adjusted in the unaudited pro forma condensed consolidated combined financial statements to give pro forma effect to events that are: (i) directly attributable to the Business Combination; (ii) factually supportable; and (iii) with respect to the statement of operations, expected to have a continuing impact on Silver Run’s results following the completion of the Transactions.
The unaudited pro forma condensed consolidated combined financial statements have been developed from and should be read in conjunction with:
• | the accompanying notes to the unaudited pro forma condensed consolidated combined financial statements; |
• | the (i) historical audited financial statements of Silver Run as of December 31, 2016 and for the period from November 16, 2016 (date of inception) to December 31, 2016 and (ii) historical condensed unaudited financial statements of Silver Run as of and for the nine months ended September 30, 2017, included elsewhere in this proxy statement; |
• | the (i) historical audited consolidated financial statements of Alta Mesa as of and for the year ended December 31, 2016 and (ii) historical condensed consolidated unaudited financial statements of Alta Mesa as of and for the nine months ended September 30, 2017, included elsewhere in this proxy statement; |
• | the (i) historical audited financial statements of Kingfisher as of and for the year ended December 31, 2016 and (ii) historical unaudited condensed consolidated financial statements of Kingfisher as of and for the nine months ended September 30, 2017, included elsewhere in this proxy statement; and |
• | other information relating to Silver Run, Alta Mesa and Kingfisher contained in this proxy statement. |
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Under Silver Run’s Charter, public stockholders have the right to redeem, upon the Closing of the Business Combination, shares of Class A Common Stock then held by them for cash equal to their pro rata share of the aggregate amount on deposit (as of two business days prior to the Closing of the Business Combination) in the Trust Account. For illustrative purposes, based on the fair value of marketable securities held in the Trust Account as of September 30, 2017 of $1,038,946,417, the estimated per share redemption price would have been approximately $10.00. Only $32,944 in redemptions were paid for 3,270 shares tendered prior to the closing of the Business Combination.
The unaudited pro forma condensed consolidated combined financial statements have been prepared as follows:
(i) | the acquisition of Alta Mesa under the Alta Mesa Contribution Agreement and Riverstone Contribution Agreement has been accounted for as a business combination using the acquisition method of accounting in accordance with ASC 805 with Silver Run as the acquirer. Under the acquisition method of accounting, the purchase price is allocated to the underlying Alta Mesa assets acquired and liabilities assumed based on their respective fair market values; and |
(ii) | the Kingfisher acquisition under the Kingfisher Contribution Agreement has been accounted for as a business combination using the acquisition method of accounting in accordance with ASC 805 with Silver Run as the acquirer. Under the acquisition method of accounting, the purchase price is allocated to the underlying Kingfisher assets acquired and liabilities assumed based on their respective fair market values. |
Silver Run has not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the unaudited pro forma adjustments are preliminary estimates and are subject to change as additional information becomes available and as additional analyses are performed. The unaudited pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma condensed consolidated combined financial statements presented below.
Silver Run has estimated the fair value of assets acquired and liabilities assumed from Alta Mesa and Kingfisher based on discussions with members of Alta Mesa’s and Kingfisher’s management, preliminary valuation studies, due diligence and information presented in the financial statements and accounting records of Alta Mesa and Kingfisher. The valuation will be finalized as soon as practicable within the required measurement period, but in no event later than 12 months following completion of the Business Combination. Any increases or decreases in the fair value of these assets and liabilities upon completion of the final valuations will result in adjustments to the balance sheet and/or statement of operations. In addition, the final purchase price of the Alta Mesa acquisition is subject to certain adjustments for inorganic acquisition capital expenditures, debt and transaction expenses, while the final purchase price of the Kingfisher acquisition is subject to certain adjustments for net working capital, debt, transaction expenses, capital expenditures and banking fees. The final purchase price and the final purchase price allocation may be different than that reflected in the preliminary purchase price allocation presented herein, and this difference may be material.
Assumptions and estimates underlying the unaudited pro forma adjustments set forth in the unaudited pro forma condensed consolidated combined financial statements are described in the accompanying notes. The unaudited pro forma condensed consolidated combined financial statements have been presented for illustrative purposes only and are not necessarily indicative of the operating results and financial position that would have been achieved had the Business Combination and the other related Transactions occurred on the dates indicated. Further, the unaudited pro forma condensed consolidated combined financial statements do not purport to project the future operating results or financial position of Silver Run following the completion of the Business Combination and the other related Transactions. The unaudited pro forma adjustments represent management’s estimates based on information available as of the date of these unaudited pro forma condensed consolidated combined financial statements and are subject to change as additional information becomes available and analyses are performed.
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Following the Closing, Silver Run will retrospectively recast Alta Mesa’s financial statements, together with Alta Mesa’s related management’s discussion and analysis of financial condition and results of operations, to report the sale of Weeks Island field and the remaining Alta Mesanon-STACK Assets Divestiture as “discontinued operations” in accordance with Accounting Standards Codification Topic205-20, “Discontinued Operations” (“ASC205-20”).
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SILVER RUN ACQUISITION CORPORATION II
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED BALANCE SHEET
AS OF SEPTEMBER 30, 2017
Silver Run (a) | Alta Mesa Historical (b) | Alta Mesa Non-STACK Assets Divestiture (c) | Alta Mesa Post Non-STACK Assets Divestitures Subtotal | Kingfisher Historical (d) | Pro Forma Adjustments | Pro Forma Combined | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||||
CURRENT ASSETS | ||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 546 | $ | 3,740 | $ | (62 | ) | $ | 3,678 | $ | 11,722 | $ | 517,412 | (e) | $ | 595,714 | ||||||||||||
59,000 | (w) | |||||||||||||||||||||||||||
3,356 | (x) | |||||||||||||||||||||||||||
Short-term restricted cash | — | 1,173 | — | 1,173 | — | — | 1,173 | |||||||||||||||||||||
Accounts receivable, net of allowance of $802 | — | 71,260 | (4,775 | ) | 66,485 | 5,231 | — | 71,716 | ||||||||||||||||||||
Other receivables | — | 679 | (154 | ) | 525 | — | — | 525 | ||||||||||||||||||||
Receivable due from affiliate | — | 839 | — | 839 | 10,028 | — | 10,867 | |||||||||||||||||||||
Prepaid expenses and other current assets | 122 | 2,215 | (1 | ) | 2,214 | 780 | — | 3,116 | ||||||||||||||||||||
Derivative financial instruments | — | 6,952 | — | 6,952 | — | (6,736 | )(y) | 216 | ||||||||||||||||||||
Investment held in Trust Account | 1,038,947 | — | — | — | — | (1,038,947 | )(f) | — | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL CURRENT ASSETS | 1,039,615 | 86,858 | (4,992 | ) | 81,866 | 27,761 | (465,915 | ) | 683,327 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
PROPERTY AND EQUIPMENT | ||||||||||||||||||||||||||||
Oil and natural gas properties, successful efforts method, net | — | 944,867 | (102,254 | ) | 842,613 | — | 1,618,528 | (y) | 2,461,141 | |||||||||||||||||||
Other property and equipment, net | — | 9,139 | (2,709 | ) | 6,430 | 228,195 | (3,112 | )(y) | 286,553 | |||||||||||||||||||
— | — | — | — | — | 55,040 | (g) | ||||||||||||||||||||||
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|
|
|
|
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|
|
|
|
|
|
| |||||||||||||||
TOTAL PROPERTY AND EQUIPMENT, NET | — | 954,006 | (104,963 | ) | 849,043 | 228,195 | 1,670,456 | 2,747,694 | ||||||||||||||||||||
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|
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|
|
| |||||||||||||||
OTHER ASSETS | ||||||||||||||||||||||||||||
Investment in LLC—cost | — | 9,000 | (9,000 | ) | — | — | — | — | ||||||||||||||||||||
Deferred financing costs, net | — | 1,943 | — | 1,943 | 3,057 | (5,000 | )(h) | — | ||||||||||||||||||||
Notes receivable due from affiliate | — | 12,121 | — | 12,121 | — | — | 12,121 | |||||||||||||||||||||
Deposits and other long-term assets | — | 14,686 | (1,185 | ) | 13,501 | 372 | — | 10,517 | ||||||||||||||||||||
(3,356 | )(x) | |||||||||||||||||||||||||||
Derivative financial instruments | — | 5,282 | — | 5,282 | — | (5,274 | )(y) | 8 | ||||||||||||||||||||
Intangible assets | — | — | — | — | — | 417,800 | (g) | 417,800 | ||||||||||||||||||||
Goodwill | — | — | — | — | — | 681,240 | (g) | 681,240 | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL OTHER ASSETS | — | 43,032 | (10,185 | ) | 32,847 | 3,429 | 1,085,410 | 1,121,686 | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL ASSETS | $ | 1,039,615 | $ | 1,083,896 | $ | (120,140 | ) | $ | 963,756 | $ | 259,385 | $ | 2,289,951 | $ | 4,552,707 | |||||||||||||
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|
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|
|
| |||||||||||||||
LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY AND EQUITY | ||||||||||||||||||||||||||||
CURRENT LIABILITIES | ||||||||||||||||||||||||||||
Accounts payable and accrued liabilities | $ | — | $ | 144,546 | $ | (5,748 | ) | $ | 138,798 | $ | 3,559 | $ | — | $ | 142,357 | |||||||||||||
Advances fromnon-operators | — | 3,872 | — | 3,872 | — | — | 3,872 | |||||||||||||||||||||
Advances from related party | — | 47,794 | — | 47,794 | — | — | 47,794 | |||||||||||||||||||||
Payables to affiliates | — | — | — | — | 6,569 | — | 6,569 | |||||||||||||||||||||
Asset retirement obligations | — | 3,960 | (3,926 | ) | 34 | — | — | 34 | ||||||||||||||||||||
Derivative financial instruments | — | 348 | — | 348 | — | 18,955 | (y) | 19,303 | ||||||||||||||||||||
Sponsor note | 1,500 | — | — | — | — | (1,500 | )(e) | — | ||||||||||||||||||||
Franchise taxes payable | 90 | — | — | — | — | — | 90 | |||||||||||||||||||||
Income taxes payable | 1,350 | — | — | — | — | — | 1,350 | |||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL CURRENT LIABILITIES | 2,940 | 200,520 | (9,674 | ) | 190,846 | 10,128 | 17,455 | 221,369 | ||||||||||||||||||||
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Fin-107
Table of Contents
Silver Run (a) | Alta Mesa Historical (b) | Alta Mesa Non-STACK Assets Divestiture (c) | Alta Mesa Post Non-STACK Assets Divestitures Subtotal | Kingfisher Historical (d) | Pro Forma Adjustments | Pro Forma Combined | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
LONG-TERM LIABILITIES | ||||||||||||||||||||||||||||
Asset retirement obligations, net of current portion | — | 65,152 | (55,419 | ) | 9,733 | — | — | 9,733 | ||||||||||||||||||||
Long-term debt, net | — | 565,247 | (22,483 | ) | 542,764 | — | — | 662,832 | ||||||||||||||||||||
— | ||||||||||||||||||||||||||||
59,000 | (w) | |||||||||||||||||||||||||||
61,068 | (y) | |||||||||||||||||||||||||||
— | ||||||||||||||||||||||||||||
Notes payable to founder | — | 27,861 | — | 27,861 | — | (27,861 | )(i) | — | ||||||||||||||||||||
Payables to affiliates | — | — | — | — | — | — | — | |||||||||||||||||||||
Deferred tax liability | — | — | — | — | — | 39,572 | (z) | 39,572 | ||||||||||||||||||||
Derivative financial instruments | — | — | — | — | — | 1,114 | (y) | 1,114 | ||||||||||||||||||||
Other long-term liabilities | — | 7,613 | (2,902 | ) | 4,711 | — | — | 4,711 | ||||||||||||||||||||
Deferred underwriting discounts | 36,225 | — | — | — | — | (36,225 | )(j) | — | ||||||||||||||||||||
Series A Preferred Stock subject to redemption; 3 (at value of $0.0001 par value) | — | N/A | N/A | N/A | N/A | — | (m) | — | ||||||||||||||||||||
Series B Preferred Stock subject to redemption; 1 (at value of $0.0001 par value) | — | N/A | N/A | N/A | N/A | — | (m) | — | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL LONG-TERM LIABILITIES | 36,225 | 665,873 | (80,804 | ) | 585,069 | — | 96,668 | 717,962 | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL LIABILITIES | 39,165 | 866,393 | (90,478 | ) | 775,915 | 10,128 | 114,123 | 939,331 | ||||||||||||||||||||
Class A common stock subject to possible redemption; 99,545,041 (at redemption value of approximately $10.00 per share) | 995,450 | N/A | N/A | N/A | N/A | (995,450 | )(k) | — | ||||||||||||||||||||
PARTNERS’ CAPITAL | — | 217,503 | (29,662 | ) | 187,841 | — | (187,841 | )(q) | — | |||||||||||||||||||
MEMBERS’ EQUITY | — | — | — | — | 249,257 | (249,257 | )(l) | — | ||||||||||||||||||||
STOCKHOLDERS’ EQUITY: | ||||||||||||||||||||||||||||
Class A common stock, $0.0001 par value | — | N/A | N/A | N/A | N/A | 17 | (p) | 17 | (v) | |||||||||||||||||||
Class B common stock, $0.0001 par value | 3 | N/A | N/A | N/A | N/A | (3 | )(n) | — | (v) | |||||||||||||||||||
Class C common stock, $0.0001 par value | — | N/A | N/A | N/A | N/A | 22 | (o) | 22 | (v) | |||||||||||||||||||
Additionalpaid-in-capital | 4,039 | N/A | N/A | N/A | N/A | 1,609,727 | (r) | 1,613,733 | ||||||||||||||||||||
(33 | )(u) | |||||||||||||||||||||||||||
Retained earnings (accumulated deficit) | 958 | N/A | N/A | N/A | N/A | (69,915 | )(s) | (68,957 | ) | |||||||||||||||||||
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|
|
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|
|
| |||||||||||||||
STOCKHOLDERS’ EQUITY | 5,000 | N/A | N/A | N/A | N/A | 1,539,815 | 1,544,815 | |||||||||||||||||||||
NON-CONTROLLING INTEREST | — | N/A | N/A | N/A | N/A | 2,068,561 | (t) | 2,068,561 | ||||||||||||||||||||
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|
|
|
|
|
|
| |||||||||||||||
TOTAL EQUITY | 5,000 | N/A | N/A | N/A | N/A | 3,608,376 | 3,613,376 | |||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 1,039,615 | $ | 1,083,896 | $ | (120,140 | ) | $ | 963,756 | $ | 259,385 | $ | 2,289,951 | $ | 4,552,707 | |||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to the unaudited pro forma condensed consolidated combined financial statements.
Fin-108
Table of Contents
SILVER RUN ACQUISITION CORPORATION II
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017
Silver Run (a) | Alta Mesa Historical (b) | Alta Mesa Non-STACK Assets Divestiture (c) | Post Non-STACK Assets Divestiture Subtotal | Kingfisher Historical (d) | Pro Forma Adjustments | Pro Forma Combined | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Operating revenues and other | ||||||||||||||||||||||||||||
Oil, natural gas and natural gas liquids | $ | — | $ | 230,205 | $ | (45,698 | ) | $ | 184,507 | $ | 62,429 | $ | — | $ | 246,936 | |||||||||||||
Midstream revenues | — | — | — | — | 29,043 | (17,792 | )(e) | 11,251 | ||||||||||||||||||||
Other revenues | — | 274 | (274 | ) | — | — | — | — | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating revenues | — | 230,479 | (45,972 | ) | 184,507 | 91,472 | (17,792 | ) | 258,187 | |||||||||||||||||||
Gain on acquisition of oil and natural gas properties | — | 6,893 | (1,626 | ) | 5,267 | — | — | 5,267 | ||||||||||||||||||||
Gain on derivative contracts | — | 38,024 | — | 38,024 | — | — | 38,024 | |||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating revenues and other | — | 275,396 | (47,598 | ) | 227,798 | 91,472 | (17,792 | ) | 301,478 | |||||||||||||||||||
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|
|
|
|
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|
|
|
|
|
|
| |||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||
Lease and plant operating expense | — | 49,836 | (21,944 | ) | 27,892 | — | — | 27,892 | ||||||||||||||||||||
Marketing and transportation | — | 21,566 | (1,080 | ) | 20,486 | — | (17,792 | )(e) | 2,694 | |||||||||||||||||||
Midstream operating expense | — | — | — | — | 69,071 | — | 69,071 | |||||||||||||||||||||
Production and ad valorem taxes | — | 8,812 | (5,101 | ) | 3,711 | 1,187 | — | 4,898 | ||||||||||||||||||||
Workover expense | — | 5,112 | (1,981 | ) | 3,131 | — | — | 3,131 | ||||||||||||||||||||
Exploration expense | — | 19,930 | (8,042 | ) | 11,888 | — | — | 11,888 | ||||||||||||||||||||
Depreciation, depletion, and amortization expense | — | 80,082 | (16,836 | ) | 63,246 | 6,893 | 27,064 | (f) | 218,689 | |||||||||||||||||||
121,486 | (l) | |||||||||||||||||||||||||||
Impairment expense | — | 29,206 | (28,018 | ) | 1,188 | — | — | 1,188 | ||||||||||||||||||||
Accretion expense | — | 1,447 | (1,213 | ) | 234 | — | — | 234 | ||||||||||||||||||||
Franchise tax expense | 90 | — | — | — | — | — | 90 | |||||||||||||||||||||
General and administrative expense | 1,547 | 35,534 | (66 | ) | 35,468 | 4,321 | — | 41,336 | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total operating expenses | 1,637 | 251,525 | (84,281 | ) | 167,244 | 81,472 | 130,758 | 381,111 | ||||||||||||||||||||
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|
|
|
|
|
|
|
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|
|
| |||||||||||||||
Income (loss) from operations | (1,637 | ) | 23,871 | 36,683 | 60,554 | 10,000 | (148,550 | ) | (79,633 | ) | ||||||||||||||||||
Other income (expense) | ||||||||||||||||||||||||||||
Interest expense, net | — | (38,189 | ) | (88 | ) | (38,277 | ) | (133 | ) | 904 | (g) | (37,506 | ) | |||||||||||||||
Other income—investment income of Trust Account | 3,946 | — | — | — | — | (3,946 | )(h) | — | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total other income (expense) | 3,946 | (38,189 | ) | (88 | ) | (38,277 | ) | (133 | ) | (3,042 | ) | (37,506 | ) | |||||||||||||||
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|
|
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|
|
|
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|
|
| |||||||||||||||
Income (loss) before income taxes | 2,309 | (14,318 | ) | 36,595 | 22,277 | 9,867 | (151,592 | ) | (117,139 | ) | ||||||||||||||||||
Provision for (benefit from) state income taxes | — | 285 | (285 | ) | — | — | (2,061 | )(i) | (2,061 | ) | ||||||||||||||||||
Provision for (benefit from) federal income taxes | 1,350 | — | — | — | — | (18,499 | )(i) | (17,149 | ) | |||||||||||||||||||
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|
|
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|
|
| |||||||||||||||
Income (loss) from continuing operations | $ | 959 | $ | (14,603 | ) | $ | 36,880 | $ | 22,277 | $ | 9,867 | $ | (131,032 | ) | $ | (97,929 | ) | |||||||||||
Income (loss) from continuing operations attributable tonon-controlling interest | — | — | — | — | — | (54,597 | )(j) | (54,597 | ) | |||||||||||||||||||
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|
| |||||||||||||||
Income (loss) from continuing operations attributable to the combined entity | $ | 959 | $ | (14,603 | ) | $ | 36,880 | $ | 22,277 | $ | 9,867 | $ | (76,435 | ) | $ | (43,332 | ) | |||||||||||
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| |||||||||||||||
Weighted average number of shares outstanding | ||||||||||||||||||||||||||||
Basic | 28,578 | 169,372 | (k) | |||||||||||||||||||||||||
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| |||||||||||||||||||||||||
Diluted | 129,375 | 169,372 | (k) | |||||||||||||||||||||||||
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|
| |||||||||||||||||||||||||
Net income (loss) per share from continuing operations | ||||||||||||||||||||||||||||
Basic | $ | 0.03 | $ | (0.26 | )(k) | |||||||||||||||||||||||
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|
| |||||||||||||||||||||||||
Diluted | $ | 0.01 | $ | (0.26 | )(k) | |||||||||||||||||||||||
|
|
|
|
See notes to the unaudited pro forma condensed consolidated combined financial statements.
Fin-109
Table of Contents
SILVER RUN ACQUISITION CORPORATION II
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2016
Silver Run (a) | Alta Mesa Historical (b) | Alta Mesa Non-STACK Assets Divestiture (c) | Alta Mesa Post Non-STACK Assets Divestiture Subtotal | Alta Mesa 2016 Refinancing Adjustment | Alta Mesa JV Wells Contribution (e) | Kingfisher Historical (f) | Pro Forma Adjustments | Pro Forma Combined | ||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||
Operating revenues and other | ||||||||||||||||||||||||||||||||||||
Oil, natural gas and natural gas liquids | $ | — | $ | 210,293 | $ | (70,287 | ) | $ | 140,006 | $ | — | $ | 26,192 | $ | 615 | $ | — | $ | 166,813 | |||||||||||||||||
Midstream revenue | — | — | — | — | — | — | 14,563 | (7,495 | )(g) | 7,068 | ||||||||||||||||||||||||||
Other revenues | — | 415 | (214 | ) | 201 | — | — | — | — | 201 | ||||||||||||||||||||||||||
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|
|
|
|
|
|
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|
|
|
|
|
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| |||||||||||||||||||
Total operating revenues | — | 210,708 | (70,501 | ) | 140,207 | — | 26,192 | 15,178 | (7,495 | ) | 174,082 | |||||||||||||||||||||||||
Gain (loss) on sale of assets | — | 3,542 | (3,539 | ) | 3 | — | — | — | — | 3 | ||||||||||||||||||||||||||
Gain (loss) on derivative contracts | — | (40,460 | ) | — | (40,460 | ) | — | — | — | — | (40,460 | ) | ||||||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues and other | — | 173,790 | (74,040 | ) | 99,750 | — | 26,192 | 15,178 | (7,495 | ) | 133,625 | |||||||||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||||||||||
Lease and plant operating expense | — | 56,893 | (29,474 | ) | 27,419 | — | 3,067 | — | — | 30,486 | ||||||||||||||||||||||||||
Marketing and transportation | — | 13,326 | (1,698 | ) | 11,628 | — | 2,780 | — | (7,495 | )(g) | 6,913 | |||||||||||||||||||||||||
Midstream operating expense | — | — | — | — | — | — | 7,431 | — | 7,431 | |||||||||||||||||||||||||||
Production and ad valorem taxes | — | 10,750 | (7,985 | ) | 2,765 | — | 529 | 187 | — | 3,481 | ||||||||||||||||||||||||||
Workover expense | — | 4,714 | (1,273 | ) | 3,441 | — | 10 | — | — | 3,451 | ||||||||||||||||||||||||||
Exploration expense | — | 24,777 | (7,547 | ) | 17,230 | — | — | — | — | 17,230 | ||||||||||||||||||||||||||
Depreciation, depletion, and amortization expense | — | 92,901 | (39,416 | ) | 53,485 | — | 9,115 | 3,752 | 22,659 | (h) | 238,880 | |||||||||||||||||||||||||
149,869 | (m) | |||||||||||||||||||||||||||||||||||
Impairment expense | — | 16,306 | (15,924 | ) | 382 | — | — | — | — | 382 | ||||||||||||||||||||||||||
Accretion expense | — | 2,174 | (1,904 | ) | 270 | — | — | — | — | 270 | ||||||||||||||||||||||||||
General and administrative expense | 2 | 41,758 | (1,290 | ) | 40,468 | — | — | 3,591 | — | 44,061 | ||||||||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 2 | 263,599 | (106,511 | ) | 157,088 | — | 15,501 | 14,961 | 165,033 | 352,585 | ||||||||||||||||||||||||||
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|
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|
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|
|
|
|
| |||||||||||||||||||
Income (loss) from operations | (2 | ) | (89,809 | ) | 32,471 | (57,338 | ) | 10,691 | 217 | (172,528 | ) | (218,960 | ) | |||||||||||||||||||||||
Other income (expense) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | — | (59,990 | ) | (10 | ) | (60,000 | ) | 17,498 | (d) | — | — | 1,209 | (i) | (41,293 | ) | |||||||||||||||||||||
Loss on extinguishment of debt | — | (18,151 | ) | — | (18,151 | ) | — | — | — | — | (18,151 | ) | ||||||||||||||||||||||||
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Total other income (expense) | — | (78,141 | ) | (10 | ) | (78,151 | ) | 17,498 | — | — | 1,209 | (59,444 | ) | |||||||||||||||||||||||
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Income (loss) before income taxes | (2 | ) | (167,950 | ) | 32,461 | (135,489 | ) | 17,498 | 10,691 | 217 | (171,319 | ) | (278,404 | ) | ||||||||||||||||||||||
Provision for (benefit from) state income taxes | — | (29 | ) | 29 | — | — | — | — | (4,804 | )(j) | (4,804 | ) | ||||||||||||||||||||||||
Provision for (benefit from) federal income taxes | — | — | — | — | — | — | — | (43,116 | )(j) | (43,116 | ) | |||||||||||||||||||||||||
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Income (loss) from continuing operations | $ | (2 | ) | $ | (167,921 | ) | $ | 32,432 | $ | (135,489 | ) | $ | 17,498 | $ | 10,691 | $ | 217 | $ | (123,399 | ) | $ | (230,484 | ) | |||||||||||||
Income (loss) from continuing operations attributable tonon-controlling interest | — | — | — | — | — | — | — | (128,498 | )(k) | (128,498 | ) | |||||||||||||||||||||||||
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Income (loss) from continuing operations attributable to the combined entity | $ | (2 | ) | $ | (167,921 | ) | $ | 32,432 | $ | (135,489 | ) | $ | 17,498 | $ | 10,691 | $ | 217 | $ | 5,099 | $ | (101,986 | ) | ||||||||||||||
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Weighted average number of shares outstanding | ||||||||||||||||||||||||||||||||||||
Basic and diluted | 25,875 | 169,372 | (l) | |||||||||||||||||||||||||||||||||
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Net income (loss) per share from continuing operations | ||||||||||||||||||||||||||||||||||||
Basic and diluted | $ | — | $ | (0.60 | )(l) | |||||||||||||||||||||||||||||||
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See notes to the unaudited pro forma condensed consolidated combined financial statements.
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NOTESTO SILVER RUN ACQUISITION CORPORATION II
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL STATEMENTS
1. Basis of Presentation
Overview
The pro forma adjustments have been prepared as if the Transactions had been consummated January 1, 2016, the beginning of the earliest period presented, in the case of the unaudited pro forma condensed consolidated combined statements of operations and on September 30, 2017 in the case of the unaudited pro forma condensed consolidated combined balance sheet.
The unaudited pro forma condensed consolidated combined financial statements have been prepared assuming the following methods of accounting in accordance with GAAP.
• | Silver Run will account for the acquisition of Alta Mesa under the Alta Mesa Contribution Agreement and the Riverstone Contribution Agreement using the acquisition method of accounting with Silver Run as the acquirer. Under the acquisition method of accounting, Alta Mesa’s assets and liabilities will be recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of Alta Mesa’s net assets acquired, if applicable, will be recorded as goodwill. |
• | Silver Run will account for the acquisition of Kingfisher under the Kingfisher Contribution Agreement using the acquisition method of accounting with Silver Run as the acquirer. Under the acquisition method of accounting, Kingfisher’s assets and liabilities will be recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of Kingfisher’s net assets acquired, if applicable, will be recorded as goodwill. |
The acquisition method of accounting is based on ASC 805, Business Combinations and uses the fair value concepts defined in ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that most assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by Silver Run, who was determined to be the accounting acquirer.
ASC 820 defines the term “fair value,” sets forth the valuation requirements for any asset or liability measured at fair value, expands related disclosure requirements and specifies a hierarchy of valuation techniques based on the nature of the inputs used to develop the fair value measures. Fair value is defined in ASC 820 as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” This is an exit price concept for the valuation of the asset or liability. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability. Fair value measurements for an asset assume the highest and best use by these market participants. Many of these fair value measurements can be highly subjective, and it is possible that other professionals, applying reasonable judgment to the same facts and circumstances, could develop and support a range of alternative estimated amounts.
Under ASC 805, acquisition-related transaction costs are not included as a component of consideration transferred but are accounted for as expenses in the periods in which such costs are incurred, or if related to the issuance of debt, capitalized as debt issuance costs. Acquisition-related transaction costs expected to be incurred as part of the Alta Mesa and Kingfisher acquisitions include estimated fees for advisory, legal and accounting fees.
The unaudited pro forma condensed consolidated combined financial statements should be read in conjunction with (i) Silver Run’s historical financial statements and related notes for the period from November 16, 2016 (date of inception) to December 31, 2016 and as of and for the nine months ended September 30, 2017, as well as “Management’s Discussion and Analysis of Financial Condition and Results of
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Operations of Silver Run,” included elsewhere in this filing, (ii) Alta Mesa historical audited consolidated financial statements and related notes for the year ended December 31, 2016 and the historical unaudited condensed consolidated financial statements as of and for the nine months ended September 30, 2017, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Alta Mesa,” included elsewhere in this filing and (iii) Kingfisher historical audited consolidated financial statements and related notes for the year ended December 31, 2016 and the historical unaudited condensed consolidated financial statements as of and for the nine months ended September 30, 2017, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Kingfisher,” included elsewhere in this filing.
The pro forma adjustments represent management’s estimates based on information available as of the date of this filing and are subject to change as additional information becomes available and additional analyses are performed. The unaudited pro forma condensed consolidated combined financial statements do not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the Business Combination that are not expected to have a continuing impact. Further,one-time transaction-related expenses anticipated to be incurred prior to, or concurrent with, closing the Business Combinations and the other related Transactions are not included in the unaudited pro forma condensed consolidated combined statements of operations. However, the impact of such transaction expenses is reflected in the unaudited pro forma condensed consolidated combined balance sheet as a decrease to retained earnings and a decrease to cash.
Preliminary Estimated SRII Opco Common Units to be issued to the Alta Mesa Contributor
Pursuant to the Alta Mesa Contribution Agreement, the Alta Mesa Contributor exchanged (i) all of its limited partner interests in Alta Mesa and (ii) all of its economic and voting rights (representing 100% and 90%, respectively) in Alta Mesa GP, the sole general partner of Alta Mesa, for 138,402,398 SRII Opco Common Units.
The number of SRII Opco Common Units issued to the Alta Mesa Contributor was as follows:
At September 30, 2017 | ||||||||
(in thousands) | ||||||||
Amount | SRII Opco Common Units | |||||||
Preliminary SRII Opco Common Units Issued to Alta Mesa Contributor | ||||||||
Initial SRII Opco Common Units | $ | — | 220,000 | |||||
Plus: Acquisition capital expenditure(1) | 64,205 | 6,421 | ||||||
Less: Amount Riverstone Contributor contributed to Alta Mesa(2) | (200,000 | ) | (20,000 | ) | ||||
Less: Alta Mesa debt assumed by SRII Opco(3) | (640,922 | ) | (64,092 | ) | ||||
Less: Alta Mesa transaction expenses(4) | (39,259 | ) | (3,926 | ) | ||||
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Total SRII Opco Common Units issued to the Alta Mesa Contributor | $ | (815,976 | ) | 138,402 | ||||
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(1) | Represents capital expenditures used by Alta Mesa between the execution date of the Alta Mesa Contribution Agreement and Closing for acquisitions of oil and gas properties, by purchase, lease or otherwise, of more than $1.0 million in a single transaction or series of related transactions in the following counties located in the State of Oklahoma: Kingfisher, Garfield, Canadian, Blaine, Major, Dewey, Woodward, Logan and Oklahoma, where Alta Mesa does not have an existing hydrocarbon interest of 25% or more. |
(2) | Represents the Riverstone Contributor $200 million contribution to Alta Mesa, in exchange for limited partner interests in Alta Mesa following the execution of the Riverstone Contribution Agreement on August 16, 2017. |
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(3) | Debt assumed by SRII Opco at Closing includes Alta Mesa’s $500 million aggregate principal amount of its 7.875% senior unsecured notes and Alta Mesa’s outstanding balance under its secured revolving credit facility at Closing. In addition, debt assumed also includes accrued interest, fees, and other expenses related to Alta Mesa’s senior unsecured notes and senior secured revolving credit facility at Closing. |
(4) | Reflects the estimated transaction costs of $13.7 million, relating to banking, legal and accounting fees associated with the Transaction, and $25.6 million related to the PARs, SERPs, and deferred compensation plans outstanding at Close pursuant to the Alta Mesa Contribution Agreement. See Note 2(e) for further details on the accounting treatment of the estimated transaction costs. |
Preliminary Estimated Purchase Price for Alta Mesa
The preliminary estimated purchase price consideration for Alta Mesa are as follows:
At September 30, 2017 | ||||
(in thousands) | ||||
Preliminary Purchase Consideration:(1) | ||||
SRII Opco Common Units (158,402,398) SRII Opco Common Units value at $8.94 per unit)(2) | $ | 1,416,117 | ||
Estimated fair value of contingentearn-out purchase consideration(3) | 280,339 | |||
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Total purchase price consideration | $ | 1,696,456 | ||
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(1) | The preliminary purchase price consideration is for the acquisition of Alta Mesa’s STACK Assets. |
(2) | At Closing, the Riverstone Contributor will receive consideration of 20,000,000 SRII Opco Common Units and the Alta Mesa Contributor will receive consideration of 138,402,398 SRII Opco Common Units. At the date of acquisition, the estimated fair value of an SRII Opco Common Unit was assumed to be $8.94 per unit, which approximates the closing stock price of Silver Run’s Class A Common Stock as of Closing on February 9, 2018. |
(3) | For a period of seven years following Closing, the Alta Mesa Contributor will be entitled to receive an aggregate of up to $800 million inearn-out consideration to be paid in the form of SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) if the20-day volume-weighted average price of the Class A Common Stock of Silver Run equals or exceeds specified prices pursuant to the Alta Mesa Contribution Agreement. Pursuant to ASC 805 and ASC 480,Distinguishing Liabilities from Equity (“ASC 480”), we have determined that theearn-out consideration valued at approximately $280.3 million will be classified as equity. Therefore at the acquisition date, theearn-out consideration will be valued at fair value and classified in stockholders’ equity. The fair value of the contingent equityearn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs using the fair value hierarchy. The key inputs included the quoted market price for Class A Common Stock, market volatility of a peer group of companies similar to Silver Run (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of eachearn-out threshold based on the remaining contractual term of the contingent liabilityearn-out period and a risk free rate based on U.S. Dollars overnight indexed swaps with a maturity equivalent to theearn-out’s expected life. |
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Preliminary Estimated Purchase Price Allocation for Alta Mesa
The following table summarizes the allocation of the preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed related to the Alta Mesa acquisition. The allocation is as follows:
At September 30, 2017 | ||||
(in thousands) | ||||
Estimated Fair Value of Assets Acquired(1) | ||||
Cash, cash equivalents and short term restricted cash(4) | $ | 63,851 | ||
Accounts Receivable | 66,485 | |||
Other Receivables | 525 | |||
Receivables due from affiliate | 839 | |||
Prepaid expenses and other current assets | 2,214 | |||
Derivative financial instruments | 216 | |||
Property and equipment:(2) | ||||
Oil and natural gas properties, successful efforts | 2,461,141 | |||
Other property and equipment, net | 3,318 | |||
Notes receivable due from affiliate | 12,121 | |||
Deposits and other long-term assets | 13,501 | |||
Derivative financial instruments | 8 | |||
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Total Assets acquired | 2,624,219 | |||
Estimated Fair Value of Liabilities Assumed(1) | ||||
Accounts payable and accrued liabilities | 138,798 | |||
Advances fromnon-operators | 3,872 | |||
Advances from related party | 47,794 | |||
Asset retirement obligations | 9,767 | |||
Derivative financial instruments | 20,417 | |||
Long-term debt, net(3)(4) | 662,832 | |||
Deferred tax liability | 39,572 | |||
Other long-term liabilities | 4,711 | |||
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Total Fair Value of liabilities assumed | 927,763 | |||
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Total consideration and fair value | $ | 1,696,456 | ||
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(1) | The preliminary purchase price allocation is allocated based on Alta Mesa’s STACK Assets. |
(2) | The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discounts rates, and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. |
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(3) | Represents the approximate fair value of Alta Mesa’s $500 million aggregate principal amount of 2024 Notes using level 1 inputs as of the acquisition date. |
(4) | This amount includes an additional $59 million of outstanding borrowings under its senior secured revolving credit facility at Closing. |
Preliminary Estimated Purchase Price for Kingfisher
The preliminary estimated purchase price consideration for Kingfisher are as follows:
At September 30, 2017 | ||||
(in thousands) | ||||
Preliminary Purchase Consideration: | ||||
Cash(1) | $ | 814,820 | ||
SRII Opco Common Units (55,000,000 SRII Opco Common Units value at $8.94 per unit)(2) | 491,700 | |||
Estimated fair value of contingentearn-out purchase consideration(3) | 93,760 | |||
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Total purchase price consideration | $ | 1,400,280 | ||
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(1) | The cash consideration after adjustments to net working capital, debt, transaction expenses, capital expenditures and banking fees were $814.8 million. |
(2) | The Kingfisher Contributor will receive consideration of 55,000,000 SRII Opco Common Units and may, at its election to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) valued at $10.00 per SRII Opco Unit if the minimum cash condition is not satisfied and the Kingfisher Contributor waives such condition. At the date of acquisition, the estimated fair value of an SRII Opco Common Unit was $8.94 per unit, which approximates the closing stock price of Silver Run’s Class A Common Stock as of the Closing on February 9, 2018. |
(3) | For a period of seven years following Closing, the Kingfisher Contributor will be entitled to receive an aggregate of up to $200 million inearn-out consideration to be paid in the form of SRII Opco Common Units (and acquire a corresponding number of shares of Class C Common Stock) if the20-day volume-weighted average price of the Class A Common Stock of Silver Run equals or exceeds specified prices pursuant to the Kingfisher Contribution Agreement. Pursuant to ASC 805 and ASC 480, we have determined that theearn-out consideration valued at approximately $93.8 million and will be classified as equity. Therefore at the acquisition date, theearn-out consideration will be valued at fair value and classified in stockholders’ equity. The fair value of the contingent equityearn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs using the fair value hierarchy. The key inputs included the quoted market price for Silver Run Class A Common Stock, market volatility of a peer group of companies similar to Silver Run (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of eachearn-out threshold based on the remaining contractual term of the contingent liabilityearn-out period and a risk free rate based on USD overnight indexed swaps with a maturity equivalent to theearn-out’s expected life. |
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Preliminary Estimated Purchase Price Allocation for Kingfisher
The following table summarizes the allocation of the preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed related to the Kingfisher acquisition. The allocation is as follows:
At September 30, 2017 | ||||
(in thousands) | ||||
Estimated Fair Value of Assets Acquired | ||||
Cash and cash equivalents | $ | 11,722 | ||
Accounts Receivable | 15,259 | |||
Prepaid expenses | 780 | |||
Property, plant and equipment:(1) | ||||
Pipeline | 275,617 | |||
Other property, plant and equipment | 7,618 | |||
Intangible assets(2) | 417,800 | |||
Goodwill(3) | 681,240 | |||
Other assets | 372 | |||
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Total Assets acquired | 1,410,408 | |||
Estimated Fair Value of Liabilities Assumed | ||||
Accounts payable | 3,559 | |||
Payable to affiliates | 6,569 | |||
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Total Fair Value of liabilities assumed | 10,128 | |||
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Total consideration and fair value | $ | 1,400,280 | ||
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(1) | The fair value measurements of crude oil, natural gas and NGL gathering, processing and storage assets are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of gathering, processing and storage assets were measured using valuation techniques that convert future cash flows to a single discounted amount. These valuations required significant judgments and estimates made by management based on assumptions believed to be reasonable at the time of the valuation, but which are inherently uncertain. The estimates and assumptions are sensitive and may be subject to change. |
(2) | The identifiable intangible assets acquired are primarily related to customer relationships held by Kingfisher prior to Closing. The intangible assets acquired were based upon the estimated fair value as of the acquisition date. The intangible assets have definite lives and are subject to amortization over their economic lives, currently ranging from approximately10-15 years. |
(3) | Goodwill is measured as the excess of the total purchase consideration over the net acquisition date fair value of the assets acquired and liabilities assumed. Goodwill will not be amortized but will be tested for impairment at least annually or whenever certain indicators of impairment are present. If, in the future, it is determined that goodwill is impaired, an impairment charge would be recorded at that time. The factors that make up the goodwill reflected in the preliminary purchase price allocation include expected synergies, including future cost efficiencies with continual flow of activity of Alta Mesa production into the Kingfisher processing facility as the basin expands, as well as other benefits that are expected to be generated. |
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2. Adjustments and Assumptions to the Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet as of September 30, 2017
The unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2017 reflects the following adjustments assuming the Transactions occurred on September 30, 2017.
a) | Represents the Silver Run unaudited historical condensed balance sheet as of September 30, 2017. |
b) | Represents the Alta Mesa unaudited historical condensed consolidated balance sheet as of September 30, 2017. |
c) | Reflects Alta Mesa’s assets and liabilities related to the sale of Alta Mesa’s Weeks Island prior toyear-end and Alta Mesa’s remaining assets and liabilities to be disposed of as part of the Alta Mesanon-STACK Assets Divestiture to transpire prior to the Closing. |
d) | Represents the Kingfisher unaudited historical condensed balance sheet as of September 30, 2017. |
e) | Represents the net adjustment to cash associated with the Transactions: |
At Sept 30, 2017 | ||||
(in thousands) | ||||
Silver Run cash previously held in Trust Account(1) | $ | 1,038,947 | ||
Cash consideration paid to Kingfisher Contributor(2) | (814,820 | ) | ||
Proceeds from IPO forward purchase agreement(3) | 400,000 | |||
Redemption payment(4) | (33 | ) | ||
Payment of deferred underwriter fees(5) | (36,225 | ) | ||
Payment of sponsor note(6) | (1,500 | ) | ||
Payment of transaction costs of Alta Mesa Contributor(7) | (39,259 | ) | ||
Payment of transaction costs of Silver Run(8) | (29,698 | ) | ||
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Net adjustments to cash associated with the Transactions | $ | 517,412 | ||
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(1) | Represents the adjustment related to the reclassification of the cash equivalents held in the Trust Account to cash and cash equivalents as described in note (f) below. |
(2) | Represents the cash consideration to the Kingfisher Contributor after adjustments at Closing for net working capital, debt, transaction expenses, capital expenditures and banking fees. See Footnote 1 for further discussion of regarding the preliminary purchase price consideration for Kingfisher. |
(3) | Represents aggregate proceeds of $400 million from the issuance of 40,000,000 shares of Class A Common Stock and 13,333,333 warrants to Fund VI Holdings pursuant to the IPO Forward Purchase Agreement. |
(4) | Represents the redemption payment for redemption of 3,270 shares of Class A Common Stock prior to the business combination. |
(5) | Represents the payment of deferred underwriting discounts attributable to Silver Run’s IPO |
(6) | Represents Silver Run repayment of outstanding sponsor note at September 30, 2017. |
(7) | Reflects the impact of preliminary estimated transaction costs totaling $13.7 million for advisory, banking, legal and accounting fees and $25.6 million of transaction costs related to Alta Mesa’s PARs, SERPs and deferred compensation plans outstanding at Closing that are not able to be capitalized as part of the Transaction. In accordance with ASC 805, acquisition-related transaction costs and related charges are not included as a component of consideration to be transferred but are required to be expensed as incurred. The unaudited pro forma condensed consolidated combined balance sheet reflects these costs as a reduction of cash with a corresponding decrease in retained earnings. These costs are not included in the unaudited pro forma condensed consolidated combined statement of operations as they are directly related to the business combination and will be nonrecurring. |
(8) | Reflects the impact of preliminary estimated transaction costs for advisory, banking, legal and accounting fees that are not capitalized as part of the Transaction. |
f) | Represents the adjustment related to the reclassification of the cash equivalents held in the Trust Account in the form of investments to cash and cash equivalents to reflect the fact that these investments are available for use in connection with the Transactions. |
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g) | The allocation of Kingfisher’s estimated fair value of consideration transferred to Kingfisher’s estimated fair value of the assets acquired and liabilities assumed resulted in the following purchase price allocation adjustments below. See Footnote 1 for further discussion regarding the preliminary purchase price consideration for Kingfisher and the preliminary purchase price allocation. |
September 30, 2017 Historical | Pro forma Adjustments | Preliminary Fair Value | ||||||||||
(in thousands) | ||||||||||||
Property, plant and equipment | ||||||||||||
Pipeline | $ | 237,688 | $ | 37,929 | $ | 275,617 | ||||||
Other property, plant and equipment | 1,152 | 6,466 | 7,618 | |||||||||
Accumulated depreciation | (10,645 | ) | 10,645 | — | ||||||||
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Property, plant and equipment, net | $ | 228,195 | $ | 55,040 | $ | 283,235 | ||||||
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Intangible assets | $ | — | $ | 417,800 | $ | 417,800 | ||||||
Goodwill | — | 681,240 | 681,240 |
h) | Represents the adjustments to deferred financing cost, net of approximately $1.9 million related to Alta Mesa and $3.1 million related to Kingfisher based on the preliminary purchase price allocation. |
i) | Represents the exchange of Alta Mesa Founder Notes for equity interest of the Alta Mesa Contributor prior to the Closing pursuant to the Alta Mesa Contribution Agreement. |
j) | Represents the payment of deferred underwriting costs of $36.2 million attributable to Silver Run’s initial IPO. |
k) | Represents an adjustment to reflect that at the time of issuance, certain of Silver Run’s Class A Common Stock was subject to a possible redemption and, as such, an amount of $995.5 million was classified as redeemable equity in Silver Run’s historical consolidated balance sheet as of September 30, 2017. Prior to Closing, public stockholders elect to have Silver Run redeem 3,270 shares in connection with the Business Combination. The remaining the shares are no longer redeemable and have been reclassified from redeemable equity to additional paid in capital and Class A Common Stock. |
l) | Represents an adjustment to eliminate Kingfisher historical members’ equity in conjunction with the Closing. |
m) | Represents the issuance of one redeemable share of Series A Preferred Stock issued to each of Bayou City, HPS and AM Management and one redeemable share of Series B Preferred Stock issued to the Riverstone Contributor in conjunction with the Closing. Such shares of Series A Preferred Stock and Series B Preferred Stock are redeemable at their par value of $0.0001 per share. |
n) | Represents the par value of the automatic conversion of 25,875,000 shares of Class B Common Stock to Class A Common Stock on aone-for-one basis in accordance with Silver Run’s Charter upon the Closing. |
o) | Represents an adjustment such that the pro forma combined Class C Common Stock at par is equal to the par value of 213,402,398 shares of Class C Common Stock outstanding after Closing, as adjusted for preliminary estimated additional debt assumed at Closing and transaction related expenses. Note 2(v) below reflects the pro forma adjustments related to adjustments to Silver Run’s Class C Common Stock as a result of the Transactions. The holders of Class C Common Stock will have the right to vote on all matters properly submitted to a vote of the Silver Run stockholders, but will not be entitled to any dividends or any distributions in liquidation from Silver Run. On or after 180 days after Closing (except that the Kingfisher Contributor may cause the redemption of up to 39,000,000 SRII Opco Common Units), the Contributors will generally have the right to cause Silver Run to redeem all or a portion of their SRII Opco Common Units in exchange for shares of Class A Common Stock, or at Silver Run’s option, an equivalent amount of cash. Upon redemption or exchange of SRII Opco Common Units held by the Contributors, a corresponding number of shares of Class C Common Stock held by such Contributor will be cancelled. |
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p) | Represents an adjustment such that the pro forma combined Class A Common Stock at par is equal to the par value of 169,371,730 shares of Class A Common Stock outstanding after Closing. Note 2(v) below reflects the pro forma adjustments related to adjustments to Class A Common Stock as a result of the Transactions. |
q) | Represents an adjustment to eliminate Alta Mesa historical partners’ capital in conjunction with the Closing |
r) | Represents an adjustment such that the pro forma combinedAdditional-paid-in-capital is equal to the amount determined as follows: |
At September 30, | ||||
2017 | ||||
(in thousands) | ||||
Net assets of Silver Run(1) | $ | 1,000,450 | ||
Less: Net cash not attributable tonon-controlling interest | (200,000 | ) | ||
Plus: Proceeds from the IPO Forward Purchase Agreement(2) | 400,000 | |||
Plus: SRII Opco Common Units issued to the Kingfisher Contributor(3) | 491,700 | |||
Plus: SRII Opco Common Units issued to Alta Mesa Contributor and Riverstone Contributor (4) | 1,416,117 | |||
Less: Transaction expenses(5) | (68,957 | ) | ||
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Total Pro Forma Combined Stockholders’ Equity before consideration of NCI | 3,039,310 | |||
Less: Pro forma combined Class A Common Stock, $0.0001 par value(6) | (17 | ) | ||
Less: Pro forma combined Class C Common Stock, $0.0001 par value(7) | (22 | ) | ||
Less Pro forma combined Accumulated loss(8) | 68,957 | |||
Less Pro forma combinedNon-controlling interests(9) | (1,694,462 | ) | ||
Less: Redemption value of 3,270 Class A Common Stock at $10.00 per share | (33 | ) | ||
Plus: Net cash not attributable tonon-controlling interest | 200,000 | |||
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Pro forma combinedadditional-paid-in-capital | 1,613,733 | |||
Less: Silver Runadditional-paid-in-capital | (4,039 | ) | ||
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Total Pro forma combinedadditional-paid-in-capital | $ | 1,609,694 | ||
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(1) | Represents the net assets of Silver Run as of September 30, 2017. |
(2) | Represents aggregate proceeds of $400 million from the issuance of 40,000,000 shares of Class A Common Stock and 13,333,333 warrants to Fund VI Holdings pursuant to the IPO Forward Purchase Agreement at Closing. |
(3) | Represents the fair value of the SRII Opco Common Units issued to the Kingfisher Contributor pursuant to the Kingfisher Contribution Agreement as discussed in Note 1. |
(4) | Represents the fair value of the SRII Opco Common Units issued to the Alta Mesa Contributor pursuant to the Alta Mesa Contribution Agreement as discussed in Note 1. |
(5) | Represents preliminary estimated transaction costs related to the Transaction described herein. See Note 2(e) above. |
(6) | Represents thepro-forma combined Class A Common Stock at par as discussed in Note 2(p) above. |
(7) | Represents thepro-forma combined Class C Common Stock at par as discussed in Note 2(o) above. |
(8) | Represents thepro-forma combined accumulated loss as discussed in Note 2(s) below. |
(9) | Represents thepro-forma combinedNon-controlling interests as discussed in Note 2(t) below. |
s) | The pro forma adjustment for retained earnings/accumulated loss reflects the adjustment necessary such that the pro forma combined retained earnings/accumulated loss reflects the Silver Run stockholders’ share of the transaction expenses. |
t) | Represents the Contributor’s share of the carrying amount of SRII Opco’s net assets calculated as follows. The Contributors will hold anon-controlling interest (“NCI”) in Silver Run comprised of 213,402,398 SRII |
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Opco Common Units and 213,402,398 shares of Class C Common Stock that is not attributable to Silver Run stockholders with an economic interest in Silver Run. |
At September 30, | ||||
2017 | ||||
(in thousands) | ||||
Total Pro Forma Combined Stockholders’ Equity (before allocation of NCI)(1) | $ | 3,039,310 | ||
Percent economic ownership of SRII Opco held by the Contributors(2) | 55.752 | % | ||
Pro forma adjustment for Silver Run NCI | $ | 1,694,462 | ||
Plus: Estimated fair value of the KingfisherEarn-out consideration(3) | 93,760 | |||
Plus: Estimated fair value of the Alta MesaEarn-out consideration(4) | 280,339 | |||
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Total Pro forma adjustment for Silver Run NCI | 2,068,561 |
(1) | See Note 2(r) above. |
(2) | Represents the percentage ownership of the SRII Opco Common Units held by the Contributors as compared to the total SRII Opco Common Units outstanding at Closing, which is calculated as the percentage of the 213,402,398 shares of Class C Common Stock outstanding at Closing divided by the total number of Class A Common Stock and Class C Common Stock assumed outstanding at Closing of 382,774,128 shares. Note 2(v) below describes the Silver Run Common Stock issued in the Transactions and outstanding following Closing. |
(3) | Represents the estimated fair value of the Kingfisherearn-out as discussed in Note 1 that is not included in the calculation of economic ownership of SRII Opco held by Silver Run. |
(4) | Represents the estimated fair value of the Alta Mesaearn-out as discussed in Note 1 that is not included in the calculation of economic ownership of SRII Opco held by Silver Run. |
u) | Represents the redemption of 3,270 shares of Class A Common Stock resulting in an aggregate payment of $32,700 from the Trust Account at Closing. |
v) | The table below reflects the authorized, issued, and outstanding shares of common and preferred stock. |
Silver Run | Pro Forma Adjustments | Pro Forma Combined | ||||||||||
Liabilities and Temporary Equity: | ||||||||||||
Redeemable Preferred Stock, $0.0001 par value | ||||||||||||
Series A preferred stock, $0.0001 par value | ||||||||||||
Designated | — | 3 | (1) | 3 | ||||||||
Issued and outstanding | — | 3 | (1) | 3 | ||||||||
Series B preferred stock, $0.0001 par value | ||||||||||||
Designated | — | 1 | (1) | 1 | ||||||||
Issued and outstanding | — | 1 | (1) | 1 | ||||||||
Class A common stock subject to possible redemption | ||||||||||||
Issued (at redemption value of approximately $10.00 per share) | 99,545,041 | (99,545,041 | )(2) | — | ||||||||
Stockholders’ Equity | ||||||||||||
Common Stock, $0.0001 par value | ||||||||||||
Class A common stock, $0.0001 par value | ||||||||||||
Authorized | 400,000,000 | 800,000,000 | (8) | 1,200,000,000 | ||||||||
Issued and outstanding | 3,954,959 | 99,545,041 | (2) | 169,371,730 | ||||||||
25,875,000 | (3) | |||||||||||
40,000,000 | (4) | |||||||||||
(3,270 | )(6) | |||||||||||
Class B common stock, $0.0001 par value | ||||||||||||
Authorized | 50,000,000 | (50,000,000 | )(3) | — | ||||||||
Issued and outstanding | 25,875,000 | (25,875,000 | )(3) | — | ||||||||
Class C common stock, $0.0001 par value | ||||||||||||
Authorized | 280,000,000 | (9) | 280,000,000 | |||||||||
Issued and outstanding(10) | — | 213,402,398 | (5) | 213,402,398 | ||||||||
Warrants | 49,633,333 | (7) | 13,333,333 | (4) | 62,966,666 |
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(1) | Designation and issuance of redeemable Series A and Series B preferred stock as described in Note (m) above. |
(2) | Represents an adjustment to reflect that at the time of issuance, certain of Silver Run’s Class A Common Stock was subject to a possible redemption. See Note (k) for additional information. |
(3) | Represents the automatic conversion of Class B Common Stock to Class A Common Stock as described in Note (n) above. Concurrently with such conversion, the number of authorized shares of Class B Common Stock shall be reduced to zero. |
(4) | Reflects the issuance of 40,000,000 shares of Class A Common Stock and warrants to purchase 13,333,333 shares of warrants of Class A Common Stock to Fund VI Holdings pursuant to the IPO Forward Purchase Agreement at Closing. |
(5) | Represents the issuance of 138,402,398 shares of Class C Common Stock, as adjusted for preliminary estimates of additional debt to be assumed by SRII Opco, 20,000,000 shares of Class C Common Stock to the Riverstone Contributor and transaction related costs, to the Alta Mesa Contributor (as described in Note 1), and 55,000,000 shares of Class C Common Stock to the Kingfisher Contributor (as described in Footnote 1). |
(6) | Represents the redemption of 3,270 shares of Class A Common Stock at $10.00 per share. |
(7) | Represents the warrants outstanding as of September 30, 2017, which includes 34,500,000 of Silver Run’s IPO warrants and 15,133,333 warrants of Silver Run Private Placement warrants. |
(8) | Stockholders approve to increase shares. |
(9) | The number of authorized shares of Class C Common Stock approved at Closing. |
(10) | Stockholder approved to establish the Class C Common Stock. The issued and outstanding shares of Class C Common Stock will equal the number of SRII Opco Common Units issued to the Contributors at Closing. |
w) | Represents Alta Mesa’s additional debt to be assumed by SRII Opco until Closing. See Note 1—preliminary estimated SRII Opco Common Units to be issued to the Alta Mesa Contributor above for further detail. |
x) | Represents legal, accounting, tax, financial and other advisor expenses incurred by Alta Mesa in connection with or incidental to preparing for the potential initial public offering of Alta Mesa Resources Inc. |
y) | The allocation of Alta Mesa’s estimated fair value of consideration transferred to Alta Mesa’s estimated fair value of the assets acquired and liabilities assumed resulted in the following purchase price allocation |
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adjustments below. See Footnote 1 for further discussion regarding the preliminary purchase price consideration for Alta Mesa and the preliminary purchase price allocation: |
At September 30, 2017 | Pro forma Adjustments | Preliminary Fair Value | ||||||||||
(in thousands) | ||||||||||||
Oil and natural gas properties, successful efforts | $ | 983,370 | $ | 692,987 | $ | 1,676,357 | ||||||
Accumulated depreciation, depletion and amortization | (231,322 | ) | 231,322 | — | ||||||||
Unproved oil and natural gas properties | 90,581 | 694,203 | 784,784 | |||||||||
Accumulated impairment of unproved properties | (16 | ) | 16 | — | ||||||||
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Total oil and natural gas properties, successful efforts | $ | 842,613 | $ | 1,618,528 | $ | 2,461,141 | ||||||
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Other property and equipment | $ | 22,332 | $ | (19,014 | ) | $ | 3,318 | |||||
Accumulated depreciation | (15,902 | ) | 15,902 | — | ||||||||
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Total other property and equipment, net | $ | 6,430 | $ | (3,112 | ) | $ | 3,318 | |||||
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Derivatives financial instruments | ||||||||||||
Derivatives Assets - current | $ | 6,952 | $ | (6,736 | ) | $ | 216 | |||||
Derivatives Assets - long-term | 5,282 | (5,274 | ) | 8 | ||||||||
Derivatives Liabilities - current | 348 | 18,955 | 19,303 | |||||||||
Derivatives Liabilities - long-term | — | 1,114 | 1,114 | |||||||||
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Total Derivatives Assets (Liabilities) | $ | 11,886 | $ | (32,079 | ) | $ | (20,193 | ) | ||||
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Long-term debt, net | ||||||||||||
7.875% senior unsecured notes due 2024(1) | $ | 500,000 | $ | 51,250 | $ | 551,250 | ||||||
Unamortized deferred financing costs | (9,818 | ) | 9,818 | — | ||||||||
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Total long-term debt, net | $ | 490,182 | $ | 61,068 | $ | 551,250 | ||||||
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(1) | The senior unsecured notes fair value as of acquisition date was based on the most recent trading values, which represents Level 1 inputs. |
z) Reflects the deferred tax liabilities arising from temporary difference between the book basis and tax basis of Silver Run’s assets and liabilities as a result of the business combination.
3) Adjustments and Assumptions to the Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations for the Nine Months Ended Sptember 30, 2017
The unaudited pro forma condensed consolidated combined statement of operations for the nine months ended Sptember 30, 2017 reflects the following adjustments assuming the Transactions occurred on January 1, 2016:
a) | Represents the Silver Run unaudited historical condensed statement of operations for the nine months ended September 30, 2017. |
b) | Represents the Alta Mesa unaudited historical condensed statement of operations for the nine months ended September 30, 2017. |
c) | Reflects the operating results of the assets disposed of as part of the Alta Mesa Weeks Island sale prior toyear-end and the remainingnon-STACK Assets Divestiture to transpire prior to the Closing. |
d) | Represents the Kingfisher unaudited historical statement of operations for the nine months ended September 30, 2017. |
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e) | Represents intersegment eliminations as a result of the combined entities of Alta Mesa and Kingfisher in conjunction with the Closing. The amounts only relate to Alta Mesa for its share of the marketing and transportation expense. The marketing and transportation expense is based on actual invoices. The remainder of the marketing and transportation invoices are charged to other interest owners and remain in the consolidated pro forma statement of operations. |
f) | Represents the adjustments to depreciation, depletion and amortization based on the preliminary purchase price allocation to the following: |
(1) | Depreciation expense was reduced by approximately $2.3 million based on the preliminary purchase price allocation to the plant, property and equipment acquired. |
(2) | Amortization expense was increased by approximately $29.4 million based on the preliminary purchase price allocation to the intangible asset assets acquired. |
g) | Represents the adjustment to reduce interest expense to reflect the exchange of Alta Mesa Founder Notes for equity interest of the Alta Mesa Contributor prior to the Closing pursuant to the Alta Mesa Contribution Agreement. |
h) | Represents the adjustment to eliminate historical interest income of Silver Run associated with the funds that were previously held in the Trust Account, which will be used to fund a portion of the cash consideration to the Kingfisher Contributor in the business combination. |
i) | Represents the associated income tax effect of pro forma adjustments attributable to Silver Run, using an estimated combined federal and state statutory income tax rate of approximately 38.9%, which reflects the corporate rate enacted at the pro forma period dates. The tax reform enacted on December 22, 2017 reduced the corporate tax rate to 21% for returns filed in and following 2018. The rate utilized in the pro forma presentation has not been updated and no effects of the tax reform have been reflected in the pro forma financial statements. |
j) | Represents net income attributable to thenon-controlling interest based on total pro forma combined net income. |
k) | Pro forma basic and diluted earnings per share was computed by dividing pro forma net loss attributable to Silver Run by the weighted average shares of Class A Common Stock, as if such shares were issued and outstanding as of January 1, 2016. The conversion of the Class C Common Stock to Class A Common Stock and warrants were excluded from the consideration of diluted earnings per share as the inclusion would have been anti-dilutive. |
l) | Represents an adjustment to increase depreciation, depletion and amortization expense based on the preliminary purchase price allocation of Alta Mesa’s oil and natural gas properties. |
4) Adjustments and Assumptions to the Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations for the Year Ended December 31, 2016
The unaudited pro forma condensed consolidated combined statement of operations for the year ended December 31, 2016 reflects the following adjustments assuming the Transactions occurred on January 1, 2016:
a) | Represents the Silver Run historical condensed statement of operation for the period from November 16, 2016 (date of inception) to December 31, 2016. |
b) | Represents the Alta Mesa historical condensed statement of operation for the year ended December 31, 2016. |
c) | Reflects the operating results of the assets disposed of as part of the Alta Mesa Weeks Island sale prior toyear-end and the remainingnon-Stack Assets Divestiture to transpire prior to the Closing. |
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d) | Interest expense reduced by approximately $7.2 million due to the decrease in the stated coupon rate of the retired 2018 Notes from 9.625% to 7.875% of the 2024 Notes. In addition, interest expense is reduced by approximately $10.3 million due to the repayment in full of Alta Mesa’s $125 million senior secured term loan. |
e) | Reflects the pro forma operating results from the date operations commenced of the Alta Mesa JV Wells contributed to us on December 31, 2016. |
f) | Represents the Kingfisher historical statement of operation for the year ended December 31, 2016. |
g) | Represents intersegment eliminations as a result of the combined entities of Alta Mesa and Kingfisher in conjunction with the Closing. The amounts only relate to Alta Mesa for its share of the marketing and transportation expense. The marketing and transportation expense is based on actual invoices. The remainder of the marketing and transportation invoices are charged to other interest owners and remain in the consolidated pro forma statement of operations. |
h) | Represents the adjustments to depreciation, depletion and amortization based on the preliminary purchase price allocation to the following: |
(1) | Amortization expense was increased by approximately $22.7 million based on the preliminary purchase price allocation to the intangible asset assets acquired. |
i) | Represents the adjustment to reduce interest expense to reflect the exchange of Alta Mesa Founder Notes for equity interest of the Alta Mesa Contributor prior to the Closing pursuant to the Alta Mesa Contribution Agreement. |
j) | Represents the associated income tax effect of pro forma adjustments attributable to Silver Run, using an estimated combined federal and state statutory income tax rate of approximately 38.9%, which reflects the corporate rate enacted at the pro forma period dates. The tax reform enacted on December 22, 2017 reduced the corporate tax rate to 21% for returns filed in and following 2018. The rate utilized in the pro forma presentation has not been updated and no effects of the tax reform have been reflected in the pro forma financial statements. |
k) | Represents net loss attributable to thenon-controlling interest based on total pro forma combined net loss. |
l) | Pro forma basic and diluted earnings per share was computed by dividing pro forma net income attributable to Silver Run by the weighted average shares of Class A Common Stock, as if such shares were issued and outstanding as of January 1, 2016. The conversion of the Class C Common Stock to Class A Common Stock and warrants were excluded from the calculation of diluted earnings per share as the inclusion would have been anti-dilutive. |
m) | Represents an adjustment to increase depreciation, depletion and amortization expense based on the preliminary purchase price allocation of Alta Mesa’s oil and natural gas properties. |
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5. Supplemental Disclosure of Oil and Gas Information
The following table provides a pro forma rollforward of the total proved reserves for the year ended December 31, 2016, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year, as if theNon-STACK Asset Divestiture and the Alta Mesa JV Wells reflected occurred on January 1, 2016:
Alta Mesa Historical (MBOE) | Alta Mesa Non-STACK Assets Divestiture (MBOE) | Post Non-STACK Assets Divestiture Subtotal | JV Wells (MBOE) | Pro forma Adjustments (MBOE) (a) | Pro Forma (MBOE) | |||||||||||||||||||
Total Proved Reserves: | ||||||||||||||||||||||||
Balance, January 1, 2016 | 78,483 | (11,473 | ) | 67,010 | — | — | 67,010 | |||||||||||||||||
Production | (7,284 | ) | 2,516 | (4,768 | ) | (709 | ) | — | (5,477 | ) | ||||||||||||||
Purchases ofreserves-in-place | 3,247 | — | 3,247 | — | (3,247 | ) | — | |||||||||||||||||
Discoveries & extensions | 69,679 | (2,348 | ) | 67,331 | 3,956 | — | 71,287 | |||||||||||||||||
Sales ofreserves-in-place | (244 | ) | 244 | — | — | — | — | |||||||||||||||||
Revisions of previous quantity | (5,124 | ) | 1,887 | (3,237 | ) | — | — | (3,237 | ) | |||||||||||||||
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Balance, December 31, 2016 | 138,757 | (9,174 | ) | 129,583 | 3,247 | (3,247 | ) | 129,583 | ||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||
January 1, 2016 | 33,859 | (8,776 | ) | 25,083 | — | — | 25,083 | |||||||||||||||||
December 31, 2016 | 40,371 | (7,262 | ) | 33,109 | — | — | 33,109 | |||||||||||||||||
Proved undeveloped reserves: | ||||||||||||||||||||||||
January 1, 2016 | 44,624 | (2,697 | ) | 41,927 | — | — | 41,927 | |||||||||||||||||
December 31, 2016 | 98,386 | (1,912 | ) | 96,474 | — | — | 96,474 |
(a) | To adjust the amount of purchases of reserves representing the Alta Mesa JV Wells contribution on December 31, 2016 included in the Alta Mesa’s historical information. |
The following pro forma standardized measure of the discounted net future cash flows and changes applicable to Alta Mesa’s proved reserves reflect the effect of income taxes assuming Alta Mesa proportionate share of the Partnership’s standardized measure had been subject to federal income tax as a subchapter C 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 the Alta Mesa’s proved oil and 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.
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The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2016:
Alta Mesa Historical | Alta Mesa Non-STACK Assets Divestiture | Post Non-STACK Assets Divestiture Subtotal | Pro Forma Adjustment | Pro Forma | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Future cash flows | $ | 3,547,130 | $ | (254,652 | ) | $ | 3,292,478 | $ | $ | 3,292,478 | ||||||||||
Future production costs | (1,811,683 | ) | 131,610 | (1,680,073 | ) | (1,680,073 | ) | |||||||||||||
Future development costs | (709,738 | ) | 98,334 | (611,404 | ) | (611,404 | ) | |||||||||||||
Future taxes on income | — | — | — | (172,299 | )(a) | (172,299 | ) | |||||||||||||
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Future net cash flows | 1,025,709 | (24,708 | ) | 1,001,001 | (172,299 | ) | 828,702 | |||||||||||||
Discount to present value at 10 percent per annum | (467,101 | ) | 563 | (466,538 | ) | 80,304 | (386,234 | ) | ||||||||||||
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Standardized measure of discounted future net cash flows | $ | 558,608 | $ | (24,145 | ) | $ | 534,463 | $ | (91,995 | ) | $ | 442,468 | ||||||||
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(a) | Reflects the associated income tax effect of Silver Run’s economic interest in SRII Opco, using an estimated combined federal and state statutory tax rate of approximately 38.9% which reflects the corporate rate enacted at the pro forma period dates. The Tax Cuts and Jobs Act enacted on December 22, 2017 reduced the corporate tax rate to 21% for returns filed in and following 2018. The rate utilized in the pro forma presentation has not been updated and no effects of the TCJA have been reflected in the pro forma financial statements. |
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The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2016:
Alta Mesa Historical | Alta Mesa Non-STACK Assets Divestiture | Post Non-STACK Assets Divestiture Subtotal | JV Wells Contribution | Pro forma Adjustments | Pro Forma | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance, January 1, 2016 | $ | 629,596 | $ | (90,656 | ) | $ | 538,940 | $ | — | $ | — | $ | 538,940 | |||||||||||
Sales of oil, and natural gas, net of production costs | (124,610 | ) | 21,683 | (102,927 | ) | (19,806 | ) | — | (122,733 | ) | ||||||||||||||
Changes in sales and transfer prices, net of production costs | (324,638 | ) | 59,135 | (265,503 | ) | — | — | (265,503 | ) | |||||||||||||||
Revisions of previous quantity estimates | (35,972 | ) | 16,581 | (19,391 | ) | — | — | (19,391 | ) | |||||||||||||||
Purchases ofreserves-in-place | 40,611 | — | 40,611 | — | (40,611 | )(a) | — | |||||||||||||||||
Sales ofreserves-in-place | 2,345 | (2,345 | ) | — | — | — | — | |||||||||||||||||
Current year discoveries and extensions | 356,631 | (31,438 | ) | 325,193 | 60,417 | — | 385,610 | |||||||||||||||||
Changes in estimated future development costs | 849 | 88 | 937 | — | — | 937 | ||||||||||||||||||
Development costs incurred during the year | 8,363 | (2,027 | ) | 6,336 | — | — | 6,336 | |||||||||||||||||
Accretion of discount | 62,960 | (9,066 | ) | 53,894 | — | — | 53,894 | |||||||||||||||||
Net change in income taxes | — | — | — | — | (91,995 | )(b) | (91,995 | ) | ||||||||||||||||
Change in production rate (timing) and other | (57,527 | ) | 13,900 | (43,627 | ) | — | — | (43,627 | ) | |||||||||||||||
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Balance, December 31, 2016 | $ | 558,608 | $ | (24,145 | ) | $ | 534,463 | $ | 40,611 | $ | (132,606 | ) | $ | 442,468 | ||||||||||
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(a) | To adjust the amount of purchases of reserves representing the Alta Mesa JV Wells on December 31, 2016 included in the Ata Mesa’s historical information. |
(b) | Reflects the associated income tax effect of Silver Run’s economic interest in SRII Opco, using an estimated combined federal and state statutory tax rate of approximately 38.9% assuming no redemption and assuming illustrative redemption. |
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EXHIBIT A: GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas industry:
“3-D seismic.” (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions.3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata thantwo-dimensional seismic data.
“Amine.” Amine treating plants remove carbon dioxide and hydrogen sulfide from natural gas.
“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.
“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 and at a ratio of one Bbl of NGL to one Bbl of oil.
“BOE/d.” One BOE per day.
“Btu” or“British Thermal Unit.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
“Completion.”The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Cryogenic.” The process of using extreme cold to separate NGLs from natural gas.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“Development costs.” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s RegulationS-X, Rule4-10(a)(7).
“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.
“DD&A.” Depreciation, depletion and amortization.
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“Differential.” An adjustment to the price of oil, natural gas or natural gas liquids 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 exploit the reservoir.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Dry hole expenses.” Expenses incurred in drilling a well, assuming a well is not successful, including plugging and abandonment expenditures.
“Dth.” 1,000,000 Btu.
“Dth/d.” 1,000,000 Btu per day.
“DUC wells.” Drilled uncompleted wells.
“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.
“Enhanced recovery.” The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
“EUR” or“Estimated ultimate recovery.”The sum of reserves remaining as of a given date and cumulative production as of that date.
“Exploitation.” A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
“Exploratory well.” An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.
“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 rocks.
“Gross wells.” The total wells in which a working interest is owned.
“Held by production.” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“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.
“Hybrid.” A combination of Swell Packers and packer systems and sleeve systems.
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“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Lease operating expenses.” The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBOE.” One thousand BOE.
“MBOE/d.” One thousand BOE per day.
“Mcf.” One thousand cubic feet of natural gas.
“Mcfe.” One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids.
“Mechanical Sleeve.” A completion device that can be operated manually to provide a flow path between the production conduit and the annual space between the casing and the formation.
“MMBOE.” One million BOE.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“MMcf/d.” One million cubic feet per day.
“MMcfe.” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
“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 others.
“Net revenue interest.” A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interest.
“NGLs” or“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.
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“Operator.” The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
“Pay.” A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.
“PDP.” Proved developing producing reserves.
“Perf.” To create holes in the casing to achieve communication between the wellbore and the reservoir.
“Play.” A geographic area with hydrocarbon potential.
“Plug.” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.
“Pooling.” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.
“Production costs.” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s RegulationS-X, Rule4-10(a)(20).
“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.
“Proration unit.” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.
“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 and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.
“Proved properties.” Properties with proved reserves.
“Proved reserves.” The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
“PUD” or“Proved undeveloped reserves.” 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 PUDs 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 process ofre-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
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“Reserves.” Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Resources.” 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.
“Royalty.” An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
“SECPV-10.” When used with respect to oil and natural gas reserves, SECPV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect tonon-property related expenses, discounted to a present value using an annual discount rate of 10%. SECPV-10 is not a financial measure calculated in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither SECPV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use SECPV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“Service well.” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection forin-situ combustion.
“Slickwater.” A common fluid in the hydraulic fracturing process made up of brackish or saline water plus a chemical additive to reduce friction to allow for high pump rates.
“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.
“STACK.” An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.
“Standardized measure.” Discounted future net cash flows estimated by applying twelve-month prices to the estimated future production ofyear-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based onperiod-end costs to determinepre-tax cash inflows. Future income
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taxes, if applicable, are computed by applying the statutory tax rate to the excess ofpre-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.
“Stratigraphic test well.” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
“Success rate.” The percentage of wells drilled which produce hydrocarbons in commercial quantities.
“Swell Packer.” A device run as part of the casing of the casing string that relies on elastomers to expand in the presence of formation fluids and isolate the formation at various intervals along the well path.
“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.
“Unproved properties.” Properties with no proved reserves.
“Waterflood.” The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.
“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 explore for and to 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.
The terms “condensate,” “development costs,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery (EUR),” “exploratory well,” “production costs,” “proved properties,” “reserves,” “reservoir,” “resources,” “service wells,” “stratigraphic test well” and “unproved properties” are defined by the SEC. Except as noted, the terms defined in this section are not the same as SEC definitions.
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March 24, 2016
Alta Mesa Holdings, L.P.
15021 Katy Freeway, Suite 400
Houston, TX 77094
Gentlemen:
At the request of Alta Mesa Holdings, L.P. (Alta Mesa), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2015 prepared by Alta Mesa’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed in early March 2016 and presented herein, was prepared for public disclosure by Alta Mesa in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Alta Mesa’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by Alta Mesa and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2015. The properties reviewed by Ryder Scott incorporate 409 reserve determinations and are located in the states of Idaho, Louisiana, Oklahoma, Texas, and West Virginia.
The properties reviewed by Ryder Scott account for a portion of Alta Mesa’s total net proved reserves as of December 31, 2015. Based on the estimates of total net proved reserves prepared by Alta Mesa, the reserves audit conducted by Ryder Scott addresses 96 percent of the total proved developed net liquid hydrocarbon reserves, 91 percent of the total proved developed net gas reserves, in excess of 99 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 99 percent of the total proved undeveloped net gas reserves of Alta Mesa. The properties reviewed by Ryder Scott account for a portion of Alta Mesa’s total proved discounted future net income using SEC hydrocarbon price parameters as of December 31, 2015. Based on the reserve and income projections prepared by Alta Mesa, the audit conducted by Ryder Scott addresses 109 percent of the total proved developed discounted future net income and in excess of 99 percent of the total proved undeveloped discounted future net income of Alta Mesa. The high percentage of audit coverage of the associated proved developed discounted future net income is the result of the “not reviewed” properties having a negative discounted future net income primarily due to future abandonment liabilities and near term operating expenses associated with properties with no reserves.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”
Based on our review, including the data, technical processes and interpretations presented by Alta Mesa, it is our opinion that the overall procedures and methodologies utilized by Alta Mesa in preparing their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Alta Mesa are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 2
The estimated reserves and future net income amounts presented in this report are related to hydrocarbon prices. Alta Mesa has informed us that in the preparation of their reserve and income projections, as of December 31, 2015, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Alta Mesa attributable to Alta Mesa’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized below:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2015
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Net Reserves of Properties | ||||||||||||||||
Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 12,120 | 2,011 | 19,157 | 33,288 | ||||||||||||
Plant Products – MBarrels | 6,853 | 17 | 11,453 | 18,323 | ||||||||||||
Gas – MMCF | 63,282 | 2,140 | 83,017 | 148,439 | ||||||||||||
Net Reserves of Properties | ||||||||||||||||
Not Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 258 | 553 | 43 | 854 | ||||||||||||
Plant Products – MBarrels | 20 | 68 | 26 | 114 | ||||||||||||
Gas – MMCF | 1,129 | 5,201 | 654 | 6,984 | ||||||||||||
Total Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 12,378 | 2,564 | 19,200 | 34,142 | ||||||||||||
Plant Products – MBarrels | 6,873 | 85 | 11,479 | 18,437 | ||||||||||||
Gas – MMCF | 64,411 | 7,341 | 83,671 | 155,423 |
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The term Mbarrels denotes 1000’s of barrels.
In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant. The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas. Alta Mesa has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 3
Because it was beyond the scope of this audit, Ryder Scott has not conducted an economic analysis to evaluate the net economic benefit from the production of the above reserves volumes. Thus, Alta Mesa’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance. The total future net income discounted at 10 percent prepared by Alta Mesa (which Ryder Scott did not review) attributable to Alta Mesa’s interest in properties that we reviewed and those properties that we did not review are summarized below:
SEC PARAMETERS
Discounted Future Net Income
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2015
Proved | ||||||||||||||||
Developed | Total Proved | |||||||||||||||
Producing | Non-Producing | Undeveloped | ||||||||||||||
Future Net Income | ||||||||||||||||
Discounted at 10% ($M) | ||||||||||||||||
Properties Reviewed by Ryder Scott | 366,972 | 46,275 | 250,340 | 663,587 | ||||||||||||
Properties Not Reviewed by Ryder Scott | (43,700 | ) | 9,036 | 673 | (33,991 | ) | ||||||||||
Total | 323,272 | 55,311 | 251,013 | 629,596 |
The discounted future net income shown above is presented at Alta Mesa’s request for your information and should not be construed as an estimate of fair market value. The term $M denotes thousands of dollars.
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part210.4-10(a). An abridged version of the SEC reserves definitions from210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status and Definitions Guidelines” in this report. The proved developed n-on producing reserves included herein consist of the shut-in and behind pipe categories.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Alta Mesa’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 4
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and
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Alta Mesa Holdings, L.P.
March 24, 2016
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their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves prepared by Alta Mesa, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 69 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available September through December 2015, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Alta Mesa or obtained from public data sources and were considered sufficient for the purpose thereof. Approximately 27 percent of the proved producing reserves that we reviewed were estimated by the analogy method. The remaining 4 percent of the proved producing reserves were estimated by the volumetric method. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Approximately 70 percent of the proved developed non-producing reserves that we reviewed were estimated by the volumetric method. Approximately 30 percent of the developed non-producing reserves that we reviewed were estimated by past performance or analogy. Approximately 94 percent of the proved undeveloped reserves that we reviewed were estimated by analogy. The remaining 6 percent was estimated by the volumetric method or a combination of methods. The volumetric analysis utilized pertinent well and geoscience data furnished to Ryder Scott by Alta Mesa for our review or which we have obtained from public data sources that were available September through December 2015. The data utilized from the analogues in conjunction with well and geoscience data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.
Horizontal wells and locations, essentially all of which are located in the Mississippi Lime, Meramec, and Oswego plays in Oklahoma, represent 82 percent of Alta Mesa’s liquids reserves and 80 percent of Alta Mesa’s gas reserves. Sixty-six percent of liquids reserves and 64 percent of gas reserves associated with horizontal drilling are proved undeveloped. The remainder are producing.
To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Alta Mesa relating to hydrocarbon prices and costs as noted herein.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 6
The hydrocarbon prices furnished by Alta Mesa for the properties reviewed by us are based on SEC price parameters using the average prices during the12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2015 for the properties reviewed by us were determined using the 12-month averagefirst-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Alta Mesa for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by Alta Mesa to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Alta Mesa were accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa.
The table below summarizes Alta Mesa’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Alta Mesa’s “average realized prices.” The average realized prices shown in the table below were determined from Alta Mesa’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Alta Mesa’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices | ||||||||
Oil/Condensate | WTI Cushing | $ | 50.28/Bbl | $ | 49.79/Bbl | |||||||
United States | NGLs | WTI Cushing | $ | 50.28/Bbl | $ | 16.77/Bbl | ||||||
Gas | Henry Hub | $ | 2.58/MMBTU | $ | 2.48/MCF |
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Alta Mesa’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. In certain cases, the gas volumes presented herein include gas consumed in operations as reserves. In those cases, the effective price was reduced such that the fuel used had no value.
Operating costs furnished by Alta Mesa are based on the operating expense reports of Alta Mesa and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Alta Mesa were accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
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Alta Mesa Holdings, L.P.
March 24, 2016
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Development costs furnished by Alta Mesa are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Alta Mesa were accepted as factual data; however, we have not conducted an independent verification of the data used by Alta Mesa. The estimated net cost of abandonment after salvage was included by Alta Mesa for properties where abandonment costs net of salvage were significant. Alta Mesa’s estimates of the net abandonment costs were accepted without independent verification.
The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Alta Mesa’s plans to develop these reserves as of December 31, 2015. The implementation of Alta Mesa’s development plans as presented to us is subject to the approval process adopted by Alta Mesa’s management. As the result of our inquiries during the course of our review, Alta Mesa has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Alta Mesa’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Alta Mesa. Alta Mesa has provided written documentation stating their commitment to proceed with the development activities as presented to us. Additionally, Alta Mesa has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by Alta Mesa were held constant throughout the life of the properties.
Alta Mesa’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by Alta Mesa to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Alta Mesa. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Alta Mesa’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Alta Mesa’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 8
The estimates of proved reserves presented herein were based upon a review of the properties in which Alta Mesa owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Alta Mesa for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of Alta Mesa are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
Alta Mesa has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Alta Mesa’s forecast of future proved production, we have relied upon data furnished by Alta Mesa with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Alta Mesa. We consider the factual data furnished to us by Alta Mesa to be appropriate and sufficient for the purpose of our review of Alta Mesa’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Alta Mesa and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by Alta Mesa, it is our opinion that the overall procedures and methodologies utilized by Alta Mesa in preparing their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Alta Mesa are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
We were in reasonable agreement with Alta Mesa’s estimates of proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance between Alta Mesa’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Alta Mesa when its reserve estimates were prepared. In these cases, Alta Mesa revised its estimates to better conform to our estimates. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Alta Mesa.
Other Properties
Other properties, as used herein, are those properties of Alta Mesa which we did not review. The proved net reserves attributable to the other properties account for approximately 2 percent of the total proved net liquid hydrocarbon reserves, approximately 5 percent of the total proved net gas reserves, and approximately negative 5 percent of the future net income discounted at 10 percent based on estimates prepared by Alta Mesa as of December 31, 2015.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 9
The same technical personnel of Alta Mesa were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored orco-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to Alta Mesa. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Alta Mesa.
We have provided Alta Mesa with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Alta Mesa and the original signed report letter, the original signed report letter shall control and supersede the digital version.
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Alta Mesa Holdings, L.P.
March 24, 2016
Page 10
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
/s/ Kevin E. Gangluff
Kevin E. Gangluff, P.E.
TBPE License No. 75852
Senior Vice President
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Kevin E. Gangluff is the primary technical person responsible for overseeing the estimate of the reserves, future production and income in this report.
Mr. Gangluff, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, is a Senior Vice President and serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies throughout North America. Before joining Ryder Scott, Mr. Gangluff served in a number of managerial, supervisory, and engineering positions with Exxon Corporation (now ExxonMobil Corporation), Texas Oil & Gas Corp., and Gruy Engineering Corp.
Mr. Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin. Mr. Gangluff is a licensed Professional Engineer in the State of Texas. He is a member of the Society of Petroleum Engineers, the Texas Independent Producers and Royalty Owners Association, and the Houston Producers Forum.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gangluff fulfills.
Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of RegulationS-X, revisions and additions to the oil and gas reporting requirements in RegulationS-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and RegulationS-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.
Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
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PETROLEUM RESERVES DEFINITIONS
Page 2
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves.Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): 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).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
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PETROLEUM RESERVES DEFINITIONS
Page 3
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the12- month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, RegulationS-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X§210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing orNon-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
(2) | wells which wereshut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or futurere-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X§210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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ALTA MESA HOLDINGS, L.P.
Estimated
Future Reserves
Attributable to Certain Leasehold Interests
SEC Parameters
As of
December 31, 2016
/s/ Michael F. Stell | /s/ Beau Utley | |||
Michael F. Stell, P.E. | Beau Utley | |||
TBPE License No. 56416 | Petroleum Engineer | |||
Advising Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.F-1580
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January 24, 2017
Tim J. Turner
VP Corporate Planning and Reserves
Alta Mesa Holdings, L.P.
15021 Katy Freeway, Suite 400
Houston, Texas 77094
Dear Mr. Turner:
At the request of Alta Mesa Holdings, L.P. (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 19, 2017 and presented herein, was prepared for public disclosure by AMH in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interestsin certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate 434 reserve determinations and are located in the states of Idaho, Louisiana, and Oklahoma.
The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves as of December 31, 2016. Based on the estimates of total net proved reserves prepared by AMH, the reserves audit conducted by Ryder Scott addresses 90 percent of the total proved developed net liquid hydrocarbon reserves, 89 percent of the total proved developed net gas reserves, 99 percent of the total proved undeveloped net liquid hydrocarbon reserves, and virtually 100 percent of the total proved undeveloped net gas reserves of AMH. The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using SEC hydrocarbon price parameters as of December 31, 2016. Although it was not included in our scope of study to review the economic analysis prepared by AMH, the net income projections for the reserves reviewed by Ryder Scott account for 104 percent of the total proved developed discounted future net income and roughly 99 percent of the total proved undeveloped discounted future net income of AMH. The high percentage of audit coverage of the associated proved developed discounted future net income is driven by the negative discounted future net income of the “non audited” properties. The negative future net income for this subset of properties is a result of future abandonment liabilities.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”
Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations, and that the overall proved reserves, on a net barrel of oil equivalent basis, for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Barrel of oil equivalents are determined by adding oil and plant products on a barrel for barrel basis and natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.
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Alta Mesa Holdings, L.P. – SEC Parameters
January 24, 2017
The estimated reserves presented in this report are related to hydrocarbon prices. AMH has informed us that in the preparation of their reserve and income projections, as of December 31, 2016, they used average prices during the12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by AMH attributable to AMH’s interest in properties that we reviewed and for those that we did not review are summarized as follows:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Net Reserves of Properties | ||||||||||||||||
Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 14,008 | 779 | 40,386 | 55,173 | ||||||||||||
Plant Products – MBarrels | 7,608 | 56 | 20,299 | 27,963 | ||||||||||||
Gas – MMCF | 81,469 | 1,879 | 221,616 | 304,964 | ||||||||||||
MBOE | 35,194 | 1,148 | 97,621 | 133,963 | ||||||||||||
Net Reserves of Properties | ||||||||||||||||
Not Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 617 | 1,428 | 581 | 2,626 | ||||||||||||
Plant Products – MBarrels | 42 | 271 | 14 | 327 | ||||||||||||
Gas – MMCF | 1,585 | 8,428 | 1,028 | 11,041 | ||||||||||||
MBOE | 923 | 3,104 | 766 | 4,793 | ||||||||||||
Total Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 14,625 | 2,207 | 40,967 | 57,799 | ||||||||||||
Plant Products – MBarrels | 7,650 | 327 | 20,313 | 28,290 | ||||||||||||
Gas – MMCF | 83,054 | 10,307 | 222,644 | 316,005 | ||||||||||||
MBOE | 36,117 | 4,252 | 98,387 | 138,756 |
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.
The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production, which are anticipated to be recovered as the result of the installation of a new and more efficient natural gas processing facility in Oklahoma. This new facility began processing the last week of May 2016, and has not yet reached full capacity. It is our understanding that Kingfisher Midstream, a gas gatherer and
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Alta Mesa Holdings, L.P. – SEC Parameters
January 24, 2017
processor, is currently processing less than 40 MMcfd, and as volumes ramp up, efficiencies will increase and the current NGL yield assumption of 75 bbl/mmcf will be achieved. We have reviewed such yields for reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. Such yields are dependent on the ability of AMH to obtain access to natural gas processing capacity capable of achieving these yields. The plant product volumes in our review are based on these facilities achieving the designed product recoveries.
In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant. The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas. AMH has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.
As stated previously, AMH did not request Ryder Scott to conduct an economic analysis of the net economic benefit from the production of the above reserves volumes. AMH’s estimates of future net income may not capture all the new and revised gas gathering, processing, compression, and other fees and expenses and potential revenue enhancements resulting from the aforementioned processing facilities located in Oklahoma. Thus, the user of this report is cautioned that AMH’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance. The total future net income discounted at 10 percent prepared by AMH (which Ryder Scott did not review) attributable to AMH’s interest in properties that we reviewed and those properties that we did not review are summarized below:
SEC PARAMETERS
Discounted Future Net Income
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Future Net Income | ||||||||||||||||
Discounted at 10% ($M) | ||||||||||||||||
Properties Reviewed by Ryder Scott | 276,025 | 13,613 | 276,857 | 566,495 | ||||||||||||
Properties Not Reviewed By Ryder Scott | (34,180 | ) | 22,505 | 3,788 | (7,887 | ) | ||||||||||
Total | 241,845 | 36,118 | 280,645 | 558,608 |
The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value. The term $M denotes thousands of dollars.
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part210.4-10(a). An abridged version of the SEC reserves definitions from210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
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The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developednon-producing reserves included herein consist of theshut-in and behind pipe categories.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:
(1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the
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uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by AMH, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AMH or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Approximately 95 percent of the proved developednon-producing reserves that we reviewed were estimated by the volumetric method. The remaining 5 percent of the developednon-producing reserves that we reviewed were estimated by historical performance. Approximately 99 percent of the proved undeveloped reserves that we reviewed were estimated by analogy. The remaining 1 percent were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by AMH for our review or which we have obtained from public data sources that were available through December 2016. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.
Horizontal wells and locations, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent 91 percent of AMH’s liquids reserves and 91 percent of AMH’s gas reserves.Seventy-six percent of liquids reserves and 77 percent of gas reserves associated with horizontal drilling are proved undeveloped. The remainder are producing.
To estimate economically recoverable proved oil and gas reserves,many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations210.4-10(a)(22)(v) and (26),
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proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by AMH for the properties reviewed by us are based on SEC price parameters using the average prices during the12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the12-month averagefirst-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by AMH for the geographic area (s) reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by AMH to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH.
The table below summarizes AMH’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as AMH’s “average realized prices.” The average realized prices shown in the table below were determined from AMH’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and AMH’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices | ||||||||
Oil/Condensate | WTI Cushing | $ | 42.75/Bbl | $ | 41.24/Bbl | |||||||
United States | NGLs | WTI Cushing | $ | 42.75/Bbl | $ | 15.18/Bbl | ||||||
Gas | Henry Hub | $ | 2.49/MMBTU | $ | 2.32/MCF |
The term MMBTU denotes millions of British thermal units.
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The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs fornon-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs furnished by AMH are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were significant. AMH’s estimates of the net abandonment costs were accepted without independent verification.
The proved developednon-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with AMH’s plans to develop these reserves as of December 31, 2016. The implementation of AMH’s development plans as presented to us is subject to the approval process adopted by AMH’s management. As the result of our inquiries during the course of our review, AMH has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by AMH’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to AMH.Where appropriate, AMH has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, AMH has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by AMH were held constant throughout the life of the properties.
AMH’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by AMH to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were
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estimated to commence at an anticipated date furnished by AMH. Wells or locations that are not currently producing may start producing earlier or later than anticipated in AMH’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
AMH’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income taxand are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of AMH are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant production yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
Audit Opinion
Based on our reserves review, including the data, technical processes and interpretations presented by AMH, including AMH’s expectation of achieving the plant product yields, it is our opinion that the overall procedures
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and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
We were in reasonable agreement with AMH’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to AMH when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.
Other Properties
Other properties, as used herein, are those properties of AMH which we did not review. The proved net reserves attributable to the other properties account for three percent of the total proved net liquid hydrocarbon reserves and three percent of the total proved net gas reserves based on estimates prepared by AMH as of December 31, 2016.
The same technical personnel of AMH were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored orco-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to AMH. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical
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persons primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by AMH.
We have provided AMH with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by AMH and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours, |
RYDER SCOTT COMPANY, L.P. |
TBPE Firm Registration No.F-1580 |
/s/ Michael F. Stell |
Michael F. Stell, P.E. |
TBPE License No. 56416 |
Advising Senior Vice President |
/s/ Beau Utley |
Beau Utley |
Petroleum Engineer |
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13hours of formalized training as well as aday-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalizedin-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented sixhours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2016, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE4-10(a) of REGULATIONS-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule4-10 of RegulationS-X, revisions and additions to the oil and gas reporting requirements in RegulationS-K, and amends and codifies Industry Guide 2 in RegulationS-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and RegulationS-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, RegulationS-X Part 210, Rule4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of theirin-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
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PETROLEUM RESERVES DEFINITIONS
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(26) defines reserves as follows:
Reserves.Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): 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 anon-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).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
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PETROLEUM RESERVES DEFINITIONS
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE4-10(a) of REGULATIONS-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, RegulationS-X Part 210, Rule4-10(a) and theSPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC andSPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing(SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be furthersub-classified according to the guidance contained in theSPE-PRMS as Producing orNon-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
DevelopedNon-Producing
DevelopedNon-Producing Reserves includeshut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
(2) | wells which wereshut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or futurere-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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ALTA MESA HOLDINGS, L.P.
Estimated
Future Reserves
Attributable to Certain Leasehold Interests
OKLAHOMA PROPERTIES
SEC Parameters
As of
December 31, 2016
/s/ Michael F. Stell | /s/ Beau Utley | |||
Michael F. Stell, P.E. | Beau Utley | |||
TBPE License No. 56416 | Petroleum Engineer | |||
Advising Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
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January 24, 2017
Tim J. Turner
VP Corporate Planning and Reserves
Alta Mesa Holdings, L.P.
15021 Katy Freeway, Suite 400
Houston, Texas 77094
Dear Mr. Turner:
At the request of Alta Mesa Holdings, L.P. (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 19, 2017 and presented herein, was prepared for public disclosure by AMH in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interestsin certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate 395 reserve determinations and are located in the state of Oklahoma.
The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves located in the state of Oklahoma as of December 31, 2016. Based on the estimates of total net proved reserves prepared by AMH, the reserves audit conducted by Ryder Scott addresses 99 percent of the total proved developed net liquid hydrocarbon reserves, 99 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of AMH. The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using SEC hydrocarbon price parameters as of December 31, 2016. Although it was not included in our scope of study to review the economic analysis prepared by AMH, the net income projections for the reserves reviewed by Ryder Scott account for 99 percent of the total proved developed discounted future net income and 100 percent of the total proved undeveloped discounted future net income of AMH’s Oklahoma properties.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”
Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations, and that the overall proved reserves, on a net barrel of oil equivalent basis, for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Barrel of oil equivalents are determined by adding oil and plant products on a barrel for barrel basis and natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.
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The estimated reserves presented in this report are related to hydrocarbon prices. AMH has informed us that in the preparation of their reserve and income projections, as of December 31, 2016, they used average prices during the12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by AMH attributable to AMH’s interest in properties that we reviewed and for those that we did not review are summarized as follows:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold Interests of
Alta Mesa Holdings, L.P.
OKLAHOMA PROPERTIES
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Net Reserves of Properties | ||||||||||||||||
Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 13,376 | 0 | 39,290 | 52,666 | ||||||||||||
Plant Products – MBarrels | 7,337 | 0 | 20,299 | 27,636 | ||||||||||||
Gas – MMCF | 72,080 | 0 | 221,308 | 293,388 | ||||||||||||
MBOE | 32,726 | 0 | 96,474 | 129,200 | ||||||||||||
Net Reserves of Properties | ||||||||||||||||
Not Audited by Ryder Scott | ||||||||||||||||
Oil/Condensate – MBarrels | 211 | 12 | 0 | 223 | ||||||||||||
Plant Products – MBarrels | 15 | 0 | 0 | 15 | ||||||||||||
Gas – MMCF | 864 | 7 | 0 | 871 | ||||||||||||
MBOE | 370 | 13 | 0 | 383 | ||||||||||||
Total Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 13,587 | 12 | 39,290 | 52,889 | ||||||||||||
Plant Products – MBarrels | 7,352 | 0 | 20,299 | 27,651 | ||||||||||||
Gas – MMCF | 72,944 | 7 | 221,308 | 294,259 | ||||||||||||
MBOE | 33,096 | 13 | 96,474 | 129,583 |
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.
The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production, which are anticipated to be recovered as the result of the installation of a new and more efficient natural gas processing facility in Oklahoma. This new facility began processing the last week of May 2016, and has not yet reached full capacity. It is our understanding that Kingfisher Midstream, a gas gatherer and processor, is currently processing less than 40 MMcfd, and as volumes ramp up, efficiencies will increase and the current NGL yield assumption of 75 bbl/mmcf will be achieved. We have reviewed such yields for reasonableness; however, we have not conducted an independent verification of the data furnished by AMH.
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Such yields are dependent on the ability of AMH to obtain access to natural gas processing capacity capable of achieving these yields. The plant product volumes in our review are based on these facilities achieving the designed product recoveries.
In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant. The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas. AMH has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.
As stated previously, AMH did not request Ryder Scott to conduct an economic analysis of the net economic benefit from the production of the above reserves volumes. AMH’s estimates of future net income may not capture all the new and revised gas gathering, processing, compression, and other fees and expenses and potential revenue enhancements resulting from the aforementioned processing facilities located in Oklahoma. Thus, the user of this report is cautioned that AMH’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance. The total future net income discounted at 10 percent prepared by AMH (which Ryder Scott did not review) attributable to AMH’s interest in properties that we reviewed and those properties that we did not review are summarized below:
SEC PARAMETERS
Discounted Future Net Income
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
OKLAHOMA PROPERTIES
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Future Net Income | ||||||||||||||||
Discounted at 10% ($M) | ||||||||||||||||
Properties Reviewed by Ryder Scott | 261,656 | 0 | 269,853 | 531,509 | ||||||||||||
Properties Not Reviewed by Ryder Scott | 2,899 | 55 | 0 | 2,954 | ||||||||||||
Total | 264,555 | 55 | 269,853 | 534,463 |
The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value. The term $M denotes thousands of dollars.
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part210.4-10(a). An abridged version of the SEC reserves definitions from210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”
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All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered
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from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by AMH, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AMH or obtained from public data sources and were considered sufficient for the purpose thereof.
Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by a combination of the analogy and volumetric methods. The data utilized from the analogues were considered sufficient for the purpose thereof.
Horizontal wells and locations, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent 97 percent of AMH’s liquids reserves and 98 percent of AMH’s gas reserves. Seventy-four percent of liquids reserves and 75 percent of gas reserves associated with horizontal drilling are proved undeveloped. The remainder are producing.
To estimate economically recoverable proved oil and gas reserves,many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by AMH for the properties reviewed by us are based on SEC price parameters using the average prices during the12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the12-month unweighted arithmetic average as previously described.
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The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the12-month averagefirst-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by AMH for the geographic area (s) reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by AMH to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH.
The table below summarizes AMH’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as AMH’s “average realized prices.” The average realized prices shown in the table below were determined from AMH’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and AMH’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices | ||||||||
Oil/Condensate | WTI Cushing | $ | 42.75/Bbl | $ | 41.27/Bbl | |||||||
United States | NGLs | WTI Cushing | $ | 42.75/Bbl | $ | 15.24/Bbl | ||||||
Gas | Henry Hub | $ | 2.49/MMBTU | $ | 2.34/MCF |
The term MMBTU denotes millions of British thermal units.
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs fornon-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs furnished by AMH are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were significant. AMH’s estimates of the net abandonment costs were accepted without independent verification.
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The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with AMH’s plans to develop these reserves as of December 31, 2016. The implementation of AMH’s development plans as presented to us is subject to the approval process adopted by AMH’s management. As the result of our inquiries during the course of our review, AMH has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by AMH’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to AMH.Where appropriate, AMH has provided written documentation supporting their commitment to proceed with the development activities as presented to us.Additionally, AMH has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by AMH were held constant throughout the life of the properties.
AMH’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by AMH to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by AMH. Wells or locations that are not currently producing may start producing earlier or later than anticipated in AMH’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
AMH’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons,drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income taxand are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of AMH are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
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AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant production yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
Audit Opinion
Based on our reserves review, including the data, technical processes and interpretations presented by AMH, including AMH’s expectation of achieving the plant product yields, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
We were in reasonable agreement with AMH’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to AMH when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.
Other Properties
Other properties, as used herein, are those Oklahoma properties of AMH which we did not review. The proved net reserves attributable to the other properties account for less than one percent of the total proved net liquid hydrocarbon reserves and less than one percent of the total proved net gas reserves based on estimates prepared by AMH as of December 31, 2016.
The same technical personnel of AMH were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
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Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored orco-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to AMH. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by AMH.
We have provided AMH with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by AMH and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours, |
RYDER SCOTT COMPANY, L.P. |
TBPE Firm Registration No.F-1580 |
/s/ Michael F. Stell |
Michael F. Stell, P.E. |
TBPE License No. 56416 |
Advising Senior Vice President |
/s/ Beau Utley |
Beau Utley |
Petroleum Engineer |
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website atwww.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13hours of formalized training as well as aday-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalizedin-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented sixhours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2016, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE4-10(a) of REGULATIONS-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule4-10 of RegulationS-X, revisions and additions to the oil and gas reporting requirements in RegulationS-K, and amends and codifies Industry Guide 2 in RegulationS-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and RegulationS-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, RegulationS-X Part 210, Rule4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of theirin-place characteristics, extraction method applied, or degree of processing prior to sale.
Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
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PETROLEUM RESERVES DEFINITIONS
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(26) defines reserves as follows:
Reserves.Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): 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 anon-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).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous
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PROVED RESERVES (SEC DEFINITIONS) CONTINUED
reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE4-10(a) of REGULATIONS-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, RegulationS-X Part 210, Rule4-10(a) and theSPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC andSPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing(SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be furthersub-classified according to the guidance contained in theSPE-PRMS as Producing orNon-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
DevelopedNon-Producing
DevelopedNon-Producing Reserves includeshut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
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(2) | wells which wereshut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or futurere-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission RegulationS-X§210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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ALTA MESA HOLDINGS, L.P.
Estimated
Future Reserves
Attributable to Certain
Leasehold and Royalty Interests
NYMEX Pricing Case
As of
December 31, 2016
/s/ Michael F. Stell | /s/ Beau Utley | |||
Michael F. Stell, P.E. | Beau Utley | |||
TBPE License No. 56416 | Petroleum Engineer | |||
Advising Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.F-1580
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January 26, 2017
Tim J. Turner
VP Corporate Planning and Reserves
Alta Mesa Holdings, L.P.
15021 Katy Freeway, Suite 400
Houston, Texas 77094
Dear Mr. Turner:
At the request of Alta Mesa Holdings, LP. (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines contained in the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System(SPE-PRMS) based on varying price and unescalated cost parameters(SPE-PRMS forecast case), provided by AMH. The income data which were not reviewed by Ryder Scott were estimated using AMH’s future price and cost parameters as noted herein. The results of our reserves audit, completed on January 19, 2017, are presented herein.
The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate 434 reserve determinations and are located in the states of Idaho, Louisiana, and Oklahoma.
The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves as of December 31, 2016. Based on the estimates of total net proved reserves prepared by AMH, the reserves audit conducted by Ryder Scott addresses 91 percent of the total proved developed net liquid hydrocarbon reserves, 90 percent of the total proved developed net gas reserves, 99 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 99 percent of the total proved undeveloped net gas reserves of AMH.
The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using NYMEX price parameters described herein as of December 31, 2016. Although it was not included in our scope of study to review the economic analysis prepared by AMH, the income projections for the reserves reviewed by Ryder Scott account for 97 percent of the total proved developed discounted future net income at 10 percent and 99 percent of the total proved undeveloped discounted future net income at 10 percent of AMH.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”
Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the currentSPE-PRMS definitions and guidelines and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate on a barrel of oil equivalent basis, reasonable within the established audit tolerance guidelines set forth in the SPE auditing standards. Barrel of oil equivalents are determined by adding oil and plant products on a barrel for barrel basis and natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.
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The estimated reserves presented in this report, as of December 31, 2016, are related to hydrocarbon prices, based on varying price parameters provided by AMH. Actual future prices may vary significantly from the prices assumed in this report; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by AMH attributable to AMH’s interest in properties that we reviewed and for those that we did not review are summarized as follows:
NYMEX PRICING CASE
Estimated Net Reserves
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Total Proved | |||||||||||||||
Producing | Non-Producing | Undeveloped | ||||||||||||||
Audited by Ryder Scott | ||||||||||||||||
Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 15,557 | 804 | 42,867 | 59,228 | ||||||||||||
Plant Products – MBarrels | 8,743 | 59 | 22,801 | 31,603 | ||||||||||||
Gas – MMCF | 94,065 | 1,938 | 249,073 | 345,076 | ||||||||||||
MBOE | 39,978 | 1,186 | 107,180 | 148,344 | ||||||||||||
Not Audited by Ryder Scott | ||||||||||||||||
Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 733 | 1,492 | 612 | 2,837 | ||||||||||||
Plant Products – MBarrels | 58 | 294 | 61 | 413 | ||||||||||||
Gas – MMCF | 2,010 | 9,127 | 2,046 | 13,183 | ||||||||||||
MBOE | 1,126 | 3,307 | 1,014 | 5,447 | ||||||||||||
Total Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 16,290 | 2,296 | 43,479 | 62,065 | ||||||||||||
Plant Products – MBarrels | 8,801 | 353 | 22,862 | 32,016 | ||||||||||||
Gas – MMCF | 96,075 | 11,065 | 251,119 | 358,259 | ||||||||||||
MBOE | 41,104 | 4,493 | 108,194 | 153,791 |
Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.
The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production, which are anticipated to be recovered as the result of the installation of a new and more efficient natural gas processing facility in Oklahoma. This new facility began processing the last week of May 2016, and has not yet reached full capacity. It is our understanding that Kingfisher Midstream, a gas gatherer and processor, is currently processing less than 40 MMcfd, and as volumes ramp up, efficiencies will increase and the
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current NGL yield assumption of 75 barrels/MMcf will be achieved. We have reviewed such yields for reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. Such yields are dependent on the ability of AMH to obtain access to natural gas processing capacity capable of achieving these yields. The plant product volumes in our review are based on these facilities achieving the designed product recoveries.
In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant. The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas. AMH has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.
As stated previously, AMH did not request Ryder Scott to conduct an economic analysis of the net economic benefit from the production of the above reserves volumes. AMH’s estimates of future net income may not capture all the new and revised gas gathering, processing, compression, and other fees and expenses and potential revenue enhancements resulting from the aforementioned processing facilities located in Oklahoma. Thus, the user of this report is cautioned that AMH’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance. The total future net income discounted at 10 percent prepared by AMH (which Ryder Scott did not review) attributable to AMH’s interest in properties that we reviewed and those properties that we did not review are summarized below:
NYMEX PRICING CASE
Discounted Future Net Income
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Total Proved | |||||||||||||||
Producing | Non-Producing | Undeveloped | ||||||||||||||
Future Net Income | ||||||||||||||||
Discounted at 10% ($M) | ||||||||||||||||
Properties Reviewed by Ryder Scott | 479,264 | 21,725 | 760,269 | 1,261,258 | ||||||||||||
Properties Not Reviewed by Ryder Scott | (25,834 | ) | 40,587 | 9,084 | 23,837 | |||||||||||
Total | 453,430 | 62,312 | 769,353 | 1,285,095 |
The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value. The term $M denotes thousands of dollars.
Reserves Included in This Report
The proved reserves presented herein conform to the definitions of reserves sponsored and approved by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE) as set forth in the 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System(SPE-PRMS). An abridged version of the SPE/WPC/AAPG/SPEE reserves terms and definitions used herein are included as attachments to this report and entitled “Petroleum Reserves Definitions.”
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The various reserve development and production status categories are defined in the attachment to this report entitled “Petroleum Reserves Status Definitions and Guidelines.” The developed provednon-producing reserves included herein consist of theshut-in and behind-pipe categories.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Recoverable petroleum resources may be classified according to theSPE-PRMS into one of three principal resource classifications: prospective resources, contingent resources, or reserves. Discovered petroleum resources may be classified as either contingent resources or as reserves depending on the chance that if a project is implemented it will reach commercial producing status (i.e. chance of commerciality). The distinction between various “classifications” of resources and reserves relates to their discovery status and increasing chance of commerciality. Commerciality is not solely determined based on the economic status of a project which refers to the situation where the income from an operation exceeds the expenses involved in, or attributable to, that operation. Conditions addressed in the determination of commerciality also include technological, economic, legal, environmental, social, and governmental factors. While economic factors are generally related to costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms and taxes. At AMH’s request, this report addresses only the reserves attributable to the properties reviewed herein and not the resources (if any).
All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. Estimates will generally be revised only as additional geologic or engineering data becomes available or as economic conditions change.
Reserves are “those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.” The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
Proved oil and gas reserves are “those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.”
Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Probable reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.” For probable reserves, it is “equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves” (cumulative 2P volumes). Possible reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than probable reserves.” For possible reserves, the “total quantities ultimately recovered from the project have a low probability to exceed the sum of the proved plus probable plus possible reserves” (cumulative 3P volumes). At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein and not the unproved reserves (if any).
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The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty.
Estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserve quantities involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of recoverable hydrocarbons is identified, the evaluator must determine the uncertainty associated with the incremental quantities of those recoverable hydrocarbons. If the quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of incremental recoverable quantities that addresses the inherent uncertainty in the estimated quantities reported.
Estimates of reserve quantities and their associated categories or classifications may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of the recoverable quantities and their associated categories or classifications may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by AMH, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AMH or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method. These methods were used where there were inadequate historical
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performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Approximately 95 percent of the proved developednon-producing reserves that we reviewed were estimated by the volumetric method. The remaining 5 percent of the developednon-producing reserves that we reviewed were estimated by historical performance. Approximately 99 percent of the proved undeveloped reserves that we reviewed were estimated by analogy. The remaining 1 percent were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by AMH for our review or which we have obtained from public data sources that were available through December 2016. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.
Horizontal wells and locations which Ryder Scott audited, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent 91 percent of AMH’s liquids reserves and 91 percent of AMH’s gas reserves. Seventy-six percent of liquids reserves and 77 percent of gas reserves associated with horizontal drilling are proved undeveloped. The remainder are producing.
To estimate recoverable oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on the cost and price assumptions as noted herein, and forecasts of future production rates. Under theSPE-PRMS Section 2.2.2 and Table 3, proved reserves must be demonstrated to be commercially recoverable under defined economic conditions, operating methods and governmental regulations from a given date forward.
As stated previously, proved reserves must be demonstrated to be commercially recoverable under defined conditions, operating methods and governmental regulations from a given date forward. To confirm that the proved reserves reviewed by us meet theSPE-PRMS guidelines to be commercially recoverable, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.
AMH furnished us with product prices for the properties reviewed by us. The future hydrocarbon price parameters used by AMH are summarized in the following table.
Year | Oil Price ($/Barrel) | Gas Price ($/MMBtu) | Plant Products Price ($/Barrel) | |||||||||
2017 | 56.195 | 3.606 | 56.195 | |||||||||
2018 | 56.594 | 3.141 | 56.594 | |||||||||
2019 | 56.097 | 2.873 | 56.097 | |||||||||
2020 | 56.048 | 2.877 | 56.048 | |||||||||
2021 | 56.205 | 2.905 | 56.205 | |||||||||
2022 Forward | 56.514 | 2.934 | 56.514 |
Product prices which were actually used for each property reviewed by us reflect adjustments for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by AMH. The term MMBtu represents million of British thermal units
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.
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Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs furnished by AMH are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were significant. AMH’s estimates of the net abandonment costs were accepted without independent verification.
Because of the direct relationship between volumes of undeveloped reserves and development plans, we include in the undeveloped category for the properties we reviewed only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. AMH has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.
Current costs used by AMH were held constant throughout the life of the properties.
AMH’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by AMH to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by AMH. Wells or locations that are not currently producing may start producing earlier or later than anticipated in AMH’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
AMH’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the
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legal rights to produce hydrocarbons,drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of AMH are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant product yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
Audit Opinion
In our opinion, AMH’s estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in the Society of Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information, and we found no bias in the utilization and analysis of data in estimates for these properties.
The overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
We were in reasonable agreement with AMH’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not
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available to AMH when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.
Other Properties
Other properties, as used herein, are those properties of AMH which we did not review. The proved net reserves attributable to the other properties account for three percent of the total proved net liquid hydrocarbon reserves, four percent of the total proved net gas reserves, and two percent of the total proved discounted future net income discounted at 10 percent based on estimates prepared by AMH as of December 31, 2016.
The same technical personnel of AMH were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately owned or publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored orco-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to AMH. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.
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Terms of Usage
This report was prepared for the exclusive use and sole benefit of Alta Mesa Holdings, L.P. and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
RYDER SCOTT COMPANY, L.P. |
TBPE Firm Registration No.F-1580 |
/s/ Michael F. Stell |
Michael F. Stell, P.E. |
TBPE License No. 56416 |
Advising Senior Vice President |
/s/ Beau Utley |
Beau Utley |
Petroleum Engineer |
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website atwww.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13hours of formalized training as well as aday-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalizedin-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented sixhours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2016, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
PREAMBLE
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.
Estimation of reserves is done under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery. Because of the differences in uncertainty, caution should be exercised when aggregating reserves of different classifications.
Reserves estimates will generally be revised as additional geologic or engineering data becomes available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations under theSPE-PRMS. Petroleum accumulations are considered as either conventional or unconventional based on the nature of theirin-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. TheSPE-PRMS acknowledges unconventional petroleum accumulations as reserves regardless of theirin-place characteristics, the extraction method applied, or the degree of processing required.
Reserves do not include quantities of petroleum being held in inventory and may be reduced for usage, processing losses and/ornon-hydrocarbons that must be removed prior to sale.
SPE-PRMS RESERVES DEFINITIONS
In March 2007, the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) jointly
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PETROLEUM RESERVES DEFINITIONS
approved the “Petroleum Resources Management System”(“SPE-PRMS”). TheSPE-PRMS consolidates, builds on, and replaces guidance previously contained in the 2000 “Petroleum Resources Classification and Definitions” and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources” publications.
The intent of the SPE, WPC, AAPG and SPEE in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms. In presenting these definitions, none of these organizations are recommending public disclosure of reserves classified as unproved. Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved and should not be construed as replacing guidelines for public disclosures under the guidelines established by regulatory and/or other governmental agencies.
Reference should be made to the fullSPE-PRMS for the complete definitions and guidelines as the following definitions, descriptions and explanations rely wholly or in part on excerpts from theSPE-PRMS document (direct passages excerpted from theSPE-PRMS document are denoted in italics herein).
RESERVES(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Section 1.1 and Table 1 define reserves as follows:
Reserves.Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may besub-classified based on project maturity and/or characterized by their development and production status.
ADDITIONAL TERMS USED IN RESERVES EVALUATIONS(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Sections 2.3, 2.3.4, 2.4 and Appendix A define the following terms as follows:
Improved recovery. Improved Recovery is the extraction of additional petroleum, beyond Primary Recovery, from naturally occurring reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes. Improved recovery also includes thermal and chemical processes to improve thein-situ mobility of viscous forms of petroleum. (Also called Enhanced Recovery.)
Improved recovery projects must meet the same Reserves commerciality criteria as primary recovery projects. There should be an expectation that the project will be economic and that the entity has committed to implement the project in a reasonable time frame (generally within 5 years; further delays should be clearly justified). If there is significant project risk, forecast incremental recoveries may be similarly categorized but should be classified as Contingent Resources.
The judgment on commerciality is based on pilot testing within the subject reservoir or by comparison to a reservoir with analogous rock and fluid properties and where a similar established improved recovery project has been successfully applied.
Incremental recoveries through improved recovery methods that have yet to be established through routine, commercially successful applications are included as Reserves only after a favorable production response from the subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the analysis on which the project is based.
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Similar to improved recovery projects applied to conventional reservoirs, successful pilots or operating projects in the subject reservoir or successful projects in analogous reservoirs may be required to establish a distribution of recovery efficiencies for non -conventional accumulations. Such pilot projects may evaluate both the extraction efficiency and the efficiency of unconventional processing facilities to derive sales products prior to custody transfer.
These incremental recoveries in commercial projects are categorized into Proved, Probable, and Possible Reserves based on certainty derived from engineering analysis and analogous applications in similar reservoirs.
Commercial. When a project is commercial, this implies that the essential social, environmental and economic conditions are met, including political, legal, regulatory and contractual conditions. In addition, a project is commercial if the degree of commitment is such that the accumulation is expected to be developed and placed on production within a reasonable time frame. While 5 years is recommended as a benchmark, a longer time frame could be applied where for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
PROVED RESERVES(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Section 2.2.2 and Table 3 define proved oil and gas reserves as follows:
Proved oil and gas reserves.Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
The area of the reservoir considered as Proved includes:
(1) the area delineated by drilling and defined by fluid contacts, if any, and
(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines”, Chapter 8).
Reserves in undeveloped locations may be classified as Proved provided that:
• | The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. |
• | Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with the drilled Proved locations. |
For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
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PETROLEUM RESERVES STATUS DEFINITIONS and GUIDELINES
As Adapted From:
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. TheSPE-PRMS Table 2 define the reserves status categories as follows:
DEVELOPED RESERVES(SPE-PRMS DEFINITIONS)
Developed Reserves are expected quantities to be recovered from existing wells and facilities.
Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be furthersub-classified as Producing orNon-Producing.
Developed Producing
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
DevelopedNon-Producing
DevelopedNon-Producing Reserves includeshut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate but which have not yet started producing; |
(2) | wells which were shut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or futurere-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
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UNDEVELOPED RESERVES(SPE-PRMS DEFINITIONS)
Undeveloped Reserves are quantities expected to be recovered through future investments.
Undeveloped Reserves are expected to be recovered from:
(1) | new wells on undrilled acreage in known accumulations; |
(2) | deepening existing wells to a different (but known) reservoir; |
(3) | infill wells that will increase recovery; or |
(4) | where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to |
(a) | recomplete an existing well; or |
(b) | install production or transportation facilities for primary or improved recovery projects. |
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ALTA MESA HOLDINGS, L.P.
Estimated
Future Reserves
Attributable to Certain
Leasehold and Royalty Interests
OKLAHOMA PROPERTIES
NYMEX Pricing Case
As of
December 31, 2016
/s/ Michael F. Stell | /s/ Beau Utley | |||
Michael F. Stell, P.E. | Beau Utley | |||
TBPE License No. 56416 | Petroleum Engineer | |||
Advising Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.F-1580
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Tim J. Turner
VP Corporate Planning and Reserves
Alta Mesa Holdings, L.P.
15021 Katy Freeway, Suite 400
Houston, Texas 77094
Dear Mr. Turner:
At the request of Alta Mesa Holdings, LP. (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines contained in the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System(SPE-PRMS) based on varying price and unescalated cost parameters(SPE-PRMS forecast case), provided by AMH. The income data which were not reviewed by Ryder Scott were estimated using AMH’s future price and cost parameters as noted herein.The results of our reserves audit, completed on January 19, 2017, are presented herein.
The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate 395 reserve determinations and are located in the state of Oklahoma.
The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves located in the state of Oklahoma as of December 31, 2016. Based on the estimates of total net proved reserves prepared by AMH for their Oklahoma properties, the reserves audit conducted by Ryder Scott addresses 99 percent of the total proved developed net liquid hydrocarbon reserves, 99 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of AMH.
The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using NYMEX price parameters described herein as of December 31, 2016. Although it was not included in our scope of study to review the economic analysis prepared by AMH, the income projections for the reserves reviewed by Ryder Scott account for 99 percent of the total proved developed discounted future net income at 10 percent and 100 percent of the total proved undeveloped discounted future net income at 10 percent of AMH’s Oklahoma properties.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”
Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their estimates of the proved reserves as of December 31, 2016 comply with the currentSPE-PRMS definitions and guidelines and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate on a barrel of
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oil equivalent basis, reasonable within the established audit tolerance guidelines set forth in the SPE auditing standards. Barrel of oil equivalents are determined by adding oil and plant products on a barrel for barrel basis and natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.
The estimated reserves presented in this report, as of December 31, 2016, are related to hydrocarbon prices, based on varying price parameters provided by AMH. Actual future prices may vary significantly from the prices assumed in this report; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by AMH attributable to AMH’s interest in properties that we reviewed and for those that we did not review are summarized as follows:
NYMEX PRICING CASE
Estimated Net Reserves
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
OKLAHOMA PROPERTIES
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Audited by Ryder Scott | ||||||||||||||||
Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 14,871 | 0 | 41,759 | 56,630 | ||||||||||||
Plant Products – MBarrels | 8,417 | 0 | 22,801 | 31,218 | ||||||||||||
Gas – MMCF | 82,382 | 0 | 248,762 | 331,144 | ||||||||||||
MBOE | 37,018 | 0 | 106,020 | 143,038 | ||||||||||||
Not Audited by Ryder Scott | ||||||||||||||||
Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 280 | 21 | 0 | 301 | ||||||||||||
Plant Products – MBarrels | 26 | 0 | 0 | 26 | ||||||||||||
Gas – MMCF | 1,135 | 13 | 0 | 1,148 | ||||||||||||
MBOE | 495 | 23 | 0 | 518 | ||||||||||||
Total Net Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 15,151 | 21 | 41,759 | 56,931 | ||||||||||||
Plant Products – MBarrels | 8,443 | 0 | 22,801 | 31,244 | ||||||||||||
Gas – MMCF | 83,517 | 13 | 248,762 | 332,292 | ||||||||||||
MBOE | 37,513 | 23 | 106,020 | 143,556 |
Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.
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The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production, which are anticipated to be recovered as the result of the installation of a new and more efficient natural gas processing facility in Oklahoma. This new facility began processing the last week of May 2016, and has not yet reached full capacity. It is our understanding that Kingfisher Midstream, a gas gatherer and processor, is currently processing less than 40 MMcfd, and as volumes ramp up, efficiencies will increase and the current NGL yield assumption of 75 barrels/MMcf will be achieved. We have reviewed such yields for reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. Such yields are dependent on the ability of AMH to obtain access to natural gas processing capacity capable of achieving these yields. The plant product volumes in our review are based on these facilities achieving the designed product recoveries.
In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant. The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas. AMH has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.
As stated previously, AMH did not request Ryder Scott to conduct an economic analysis of the net economic benefit from the production of the above reserves volumes. AMH’s estimates of future net income may not capture all the new and revised gas gathering, processing, compression, and other fees and expenses and potential revenue enhancements resulting from the aforementioned processing facilities located in Oklahoma. Thus, the user of this report is cautioned that AMH’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance. The total future net income discounted at 10 percent prepared by AMH (which Ryder Scott did not review) attributable to AMH’s interest in properties that we reviewed and those properties that we did not review are summarized below:
NYMEX PRICING CASE
Discounted Future Net Income
Certain Leasehold and Royalty Interests of
Alta Mesa Holdings, L.P.
OKLAHOMA PROPERTIES
As of December 31, 2016
Proved | ||||||||||||||||
Developed | Undeveloped | Total Proved | ||||||||||||||
Producing | Non-Producing | |||||||||||||||
Future Net Income | ||||||||||||||||
Discounted at 10% ($M) | ||||||||||||||||
Properties Reviewed by Ryder Scott | 449,086 | 0 | 743,790 | 1,192,876 | ||||||||||||
Properties Not Reviewed by Ryder Scott | 6,140 | 213 | 0 | 6,353 | ||||||||||||
Total | 455,226 | 213 | 743,790 | 1,199,229 |
The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value. The term $M denotes thousands of dollars.
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Reserves Included in This Report
The proved reserves presented herein conform to the definitions of reserves sponsored and approved by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE) as set forth in the 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System(SPE-PRMS). An abridged version of the SPE/WPC/AAPG/SPEE reserves terms and definitions used herein are included as attachments to this report and entitled “Petroleum Reserves Definitions.”
The various reserve development and production status categories are defined in the attachment to this report entitled “Petroleum Reserves Status Definitions and Guidelines.”
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Recoverable petroleum resources may be classified according to theSPE-PRMS into one of three principal resource classifications: prospective resources, contingent resources, or reserves. Discovered petroleum resources may be classified as either contingent resources or as reserves depending on the chance that if a project is implemented it will reach commercial producing status (i.e. chance of commerciality). The distinction between various “classifications” of resources and reserves relates to their discovery status and increasing chance of commerciality. Commerciality is not solely determined based on the economic status of a project which refers to the situation where the income from an operation exceeds the expenses involved in, or attributable to, that operation. Conditions addressed in the determination of commerciality also include technological, economic, legal, environmental, social, and governmental factors. While economic factors are generally related to costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms and taxes. At AMH’s request, this report addresses only the reserves attributable to the properties reviewed herein and not the resources (if any).
All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. Estimates will generally be revised only as additional geologic or engineering data becomes available or as economic conditions change.
Reserves are “those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.” The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
Proved oil and gas reserves are “those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.”
Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Probable reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.” For probable reserves, it is “equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves” (cumulative 2P volumes). Possible reserves are “those additional
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reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than probable reserves.” For possible reserves, the “total quantities ultimately recovered from the project have a low probability to exceed the sum of the proved plus probable plus possible reserves” (cumulative 3P volumes). At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein and not the unproved reserves (if any).
The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty.
Estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, could be more or less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserve quantities involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of recoverable hydrocarbons is identified, the evaluator must determine the uncertainty associated with the incremental quantities of those recoverable hydrocarbons. If the quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of incremental recoverable quantities that addresses the inherent uncertainty in the estimated quantities reported.
Estimates of reserve quantities and their associated categories or classifications may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of the recoverable quantities and their associated categories or classifications may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by AMH, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through
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December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AMH or obtained from public data sources and were considered sufficient for the purpose thereof.
Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by a combination of the analogy and volumetric methods. The data utilized from the analogues were considered sufficient for the purpose thereof.
Horizontal wells and locations which Ryder Scott audited, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent 97 percent of AMH’s liquids reserves and 97 percent of AMH’s gas reserves. Seventy-six percent of liquids reserves and 77 percent of gas reserves associated with horizontal drilling are proved undeveloped. The remainder are producing.
To estimate recoverable oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on the cost and price assumptions as noted herein, and forecasts of future production rates. Under theSPE-PRMS Section 2.2.2 and Table 3, proved reserves must be demonstrated to be commercially recoverable under defined economic conditions, operating methods and governmental regulations from a given date forward.
As stated previously, proved reserves must be demonstrated to be commercially recoverable under defined conditions, operating methods and governmental regulations from a given date forward. To confirm that the proved reserves reviewed by us meet theSPE-PRMS guidelines to be commercially recoverable, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.
AMH furnished us with product prices for the properties reviewed by us. The future hydrocarbon price parameters used by AMH are summarized in the following table.
Year | Oil Price ($/Barrel) | Gas Price ($/MMBtu) | Plant Products Price ($/Barrel) | |||||||||
2017 | 56.195 | 3.606 | 56.195 | |||||||||
2018 | 56.594 | 3.141 | 56.594 | |||||||||
2019 | 56.097 | 2.873 | 56.097 | |||||||||
2020 | 56.048 | 2.877 | 56.048 | |||||||||
2021 | 56.205 | 2.905 | 56.205 | |||||||||
2022 Forward | 56.514 | 2.934 | 56.514 |
Product prices which were actually used for each property reviewed by us reflect adjustments for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by AMH. The term MMBtu represents million of British thermal units
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
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Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs furnished by AMH are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH. The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were significant. AMH’s estimates of the net abandonment costs were accepted without independent verification.
Because of the direct relationship between volumes of undeveloped reserves and development plans, we include in the undeveloped category for the properties we reviewed only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. AMH has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.
Current costs used by AMH were held constant throughout the life of the properties.
AMH’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by AMH to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by AMH. Wells or locations that are not currently producing may start producing earlier or later than anticipated in AMH’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
AMH’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons,drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
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The estimates of reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of AMH are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant product yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
Audit Opinion
In our opinion, AMH’s estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in the Society of Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information, and we found no bias in the utilization and analysis of data in estimates for these properties.
The overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
We were in reasonable agreement with AMH’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to AMH when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.
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Other Properties
Other properties, as used herein, are those Oklahoma properties of AMH which we did not review. The proved net reserves attributable to the other properties account for less than one percent of the total proved net liquid hydrocarbon reserves, less than one percent of the total proved net gas reserves, and less than one percent of the total proved discounted future net income discounted at 10 percent based on estimates prepared by AMH as of December 31, 2016.
The same technical personnel of AMH were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately owned or publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored orco-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to AMH. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
This report was prepared for the exclusive use and sole benefit of Alta Mesa Holdings, L.P. and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
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RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.F-1580
/s/ Michael F. Stell |
Michael F. Stell, P.E. |
TBPE License No. 56416 |
Advising Senior Vice President |
/s/ Beau Utley |
Beau Utley |
Petroleum Engineer |
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13hours of formalized training as well as aday-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalizedin-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented sixhours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2016, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
PREAMBLE
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be furthersub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.
Estimation of reserves is done under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery. Because of the differences in uncertainty, caution should be exercised when aggregating reserves of different classifications.
Reserves estimates will generally be revised as additional geologic or engineering data becomes available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations under theSPE-PRMS. Petroleum accumulations are considered as either conventional or unconventional based on the nature of theirin-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. TheSPE-PRMS acknowledges unconventional petroleum accumulations as reserves regardless of theirin-place characteristics, the extraction method applied, or the degree of processing required.
Reserves do not include quantities of petroleum being held in inventory and may be reduced for usage, processing losses and/ornon-hydrocarbons that must be removed prior to sale.
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PETROLEUM RESERVES DEFINITIONS
SPE-PRMS RESERVES DEFINITIONS
In March 2007, the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) jointly approved the “Petroleum Resources Management System”(“SPE-PRMS”). TheSPE-PRMS consolidates, builds on, and replaces guidance previously contained in the 2000 “Petroleum Resources Classification and Definitions” and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources” publications.
The intent of the SPE, WPC, AAPG and SPEE in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms. In presenting these definitions, none of these organizations are recommending public disclosure of reserves classified as unproved. Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved and should not be construed as replacing guidelines for public disclosures under the guidelines established by regulatory and/or other governmental agencies.
Reference should be made to the fullSPE-PRMS for the complete definitions and guidelines as the following definitions, descriptions and explanations rely wholly or in part on excerpts from theSPE-PRMS document (direct passages excerpted from theSPE-PRMS document are denoted in italics herein).
RESERVES(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Section 1.1 and Table 1 define reserves as follows:
Reserves.Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may besub-classified based on project maturity and/or characterized by their development and production status.
ADDITIONAL TERMS USED IN RESERVES EVALUATIONS(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Sections 2.3, 2.3.4, 2.4 and Appendix A define the following terms as follows:
Improved recovery. Improved Recovery is the extraction of additional petroleum, beyond Primary Recovery, from naturally occurring reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes. Improved recovery also includes thermal and chemical processes to improve thein-situ mobility of viscous forms of petroleum. (Also called Enhanced Recovery.)
Improved recovery projects must meet the same Reserves commerciality criteria as primary recovery projects. There should be an expectation that the project will be economic and that the entity has committed to implement the project in a reasonable time frame (generally within 5 years; further delays should be clearly justified). If there is significant project risk, forecast incremental recoveries may be similarly categorized but should be classified as Contingent Resources.
The judgment on commerciality is based on pilot testing within the subject reservoir or by comparison to a reservoir with analogous rock and fluid properties and where a similar established improved recovery project has been successfully applied.
Incremental recoveries through improved recovery methods that have yet to be established through routine, commercially successful applications are included as Reserves only after a favorable production response from
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PETROLEUM RESERVES DEFINITIONS
the subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the analysis on which the project is based.
Similar to improved recovery projects applied to conventional reservoirs, successful pilots or operating projects in the subject reservoir or successful projects in analogous reservoirs may be required to establish a distribution of recovery efficiencies fornon-conventional accumulations. Such pilot projects may evaluate both the extraction efficiency and the efficiency of unconventional processing facilities to derive sales products prior to custody transfer.
These incremental recoveries in commercial projects are categorized into Proved, Probable, and Possible Reserves based on certainty derived from engineering analysis and analogous applications in similar reservoirs.
Commercial. When a project is commercial, this implies that the essential social, environmental and economic conditions are met, including political, legal, regulatory and contractual conditions. In addition, a project is commercial if the degree of commitment is such that the accumulation is expected to be developed and placed on production within a reasonable time frame. While 5 years is recommended as a benchmark, a longer time frame could be applied where for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
PROVED RESERVES(SPE-PRMS DEFINITIONS)
TheSPE-PRMS Section 2.2.2 and Table 3 define proved oil and gas reserves as follows:
Proved oil and gas reserves.Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
The area of the reservoir considered as Proved includes:
(1) the area delineated by drilling and defined by fluid contacts, if any, and
(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines”, Chapter 8).
Reserves in undeveloped locations may be classified as Proved provided that:
• | The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. |
• | Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with the drilled Proved locations. |
For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
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PETROLEUM RESERVES STATUS DEFINITIONS and GUIDELINES
As Adapted From:
PETROLEUM RESOURCES MANAGEMENT SYSTEM(SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. TheSPE-PRMS Table 2 define the reserves status categories as follows:
DEVELOPED RESERVES(SPE-PRMS DEFINITIONS)
Developed Reserves are expected quantities to be recovered from existing wells and facilities.
Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be furthersub-classified as Producing orNon-Producing.
Developed Producing
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
DevelopedNon-Producing
DevelopedNon-Producing Reserves includeshut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) | completion intervals which are open at the time of the estimate but which have not yet started producing; |
(2) | wells which wereshut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or futurere-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
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PETROLEUM RESERVES STATUS DEFINITIONS and GUIDELINES
UNDEVELOPED RESERVES(SPE-PRMS DEFINITIONS)
Undeveloped Reserves are quantities expected to be recovered through future investments.
Undeveloped Reserves are expected to be recovered from:
(1) | new wells on undrilled acreage in known accumulations; |
(2) | deepening existing wells to a different (but known) reservoir; |
(3) | infill wells that will increase recovery; or |
(4) | where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to |
(a) | recomplete an existing well; or |
(b) | install production or transportation facilities for primary or improved recovery projects. |
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PART II—INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. | Other Expenses of Issuance and Distribution |
The following table sets forth the costs and expenses payable by the registrant in connection with this offering. All of the amounts shown are estimates except the Securities and Exchange Commission (the “SEC”) registration fee.
SEC Registration Fee | $ | 380,000 | ||
Legal Fees and Expenses | 500,000 | |||
Accounting Fees and Expenses | 600,000 | |||
Other | 400,000 | |||
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| |||
Total | $ | 1,880,000 | ||
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We will bear all costs, expenses and fees in connection with the registration of the shares of Class A Common Stock, including with regard to compliance with state securities or “blue sky” laws. The selling stockholders, however, will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock.
Item 14. | Indemnification of Directors and Officers |
Reference is made to Section 102(b)(7) of the Delaware General Corporation Law (the “DGCL”), which enables a corporation in its original certificate of incorporation or an amendment thereto to eliminate or limit the personal liability of a director for violations of the director’s fiduciary duty, except (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders; (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law; (3) pursuant to Section 174 of the DGCL, which provides for liability of directors for unlawful payments of dividends or unlawful stock purchases or redemptions or; (4) for any transaction from which a director derived an improper personal benefit.
Reference is also made to Section 145 of the DGCL, which provides that a corporation may indemnify any person, including an officer or director, who was or is, or is threatened to be made, party to any threatened, pending or completed legal action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation) by reason of the fact that such person is or was an officer, director, employee or agent of such corporation or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such officer, director, employee or agent acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the corporation’s best interest and, for criminal proceedings, had no reasonable cause to believe that his conduct was unlawful. A Delaware corporation may indemnify any officer or director in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses that such officer or director actually and reasonably incurred in connection therewith.
In accordance with Section 102(b)(7) of the DGCL, our second amended and restated certificate of incorporation (our “Charter”) provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of its fiduciary duty as a director, except to the extent such limitation on or exemption from liability is not permitted under the DGCL unless he or she violated their duty of loyalty to the Registrant or its stockholders, acted in bad faith, knowingly or intentionally violated the law, authorized unlawful payments of dividends, unlawful stock purchases or unlawful redemptions, or derived improper personal benefit from their actions as directors. The effect of this provision of Charter is to eliminate
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our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seeknon-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.
If the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our Charter, the liability of our directors to us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our Charter limiting or eliminating the liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.
Our Charter also provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former officers and directors, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney’s fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our Charter will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.
The right to indemnification conferred by our Charter is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately determined that such person is not entitled to be indemnified for such expenses under our Charter or otherwise.
The rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our Charter may have or hereafter acquire under law, our Charter, our amended and restated bylaws (our “Bylaws”), an agreement, vote of stockholders or disinterested directors, or otherwise.
Any repeal or amendment of provisions of our Charter affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our Charter will also permit us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our Charter.
Our Bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our Charter. In addition, our Bylaws provide for a right of indemnity to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our Bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.
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Any repeal or amendment of provisions of our Bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision.
We have entered into indemnity agreements with each of our officers and directors. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law and to advance expenses incurred as a result of any proceeding against them to which they could be indemnified.
Item 15. | Recent Sales of Unregistered Securities |
Since our formation, we have sold the following securities without registration under the Securities Act:
On November 21, 2016, Silver Run Sponsor II, LLC, our sponsor, acquired an aggregate of 11,500,000 shares of our Class B common stock, in exchange for a capital contribution of $25,000, or approximately $0.002 per share. Such securities were issued in connection with our organization pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. Our sponsor is an accredited investor for purposes of Rule 501 of Regulation D under the Securities Act.
In addition, March 29, 2017, simultaneously with the completion of our initial public offering, our sponsor purchased from us an aggregate of 15,133,333 private placement warrants at $1.50 per warrant (for an aggregate purchase price of $22,700,000). This purchase took place on a private placement basis. This issuance was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. Our sponsor is an accredited investor for purposes of Rule 501 of Regulation D under the Securities Act.
On March 17, 2017, we entered into a forward purchase agreement pursuant to which Fund VI Holdings agreed to purchase an aggregate of up to 40,000,000 shares of our Class A common stock, plus an aggregate of up to 13,333,333 warrants, for an aggregate purchase price of up to $400,000,000 upon the closing of our initial business combination. We closed on the purchase of these securities on February 9, 2018. These issuances took place on a private placement basis. These issuances have been and will be made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. Fund VI Holdings is an accredited investor for purposes of Rule 501 of Regulation D under the Securities Act.
On the Closing Date, the Company issued 213,402,398 shares of Class C Common Stock to the Contributors and (i) one share of our Series A Preferred Stock to each of Bayou City Energy Management, LLC, HPS Investment Partners, LLC and AM Equity Holdings, LP, and (ii) one share of our Series B Preferred Stock to Fund VI Holdings in connection with the Business Combination. These issuances were made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.
No underwriting discounts or commissions were paid with respect to such sales
Item 16. | Exhibits |
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# | Pursuant to Rule 406T of RegulationS-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections. |
* | Filed herewith. |
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Item 17. | Undertakings |
The undersigned registrant hereby undertakes:
(a)(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
i. | To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933; |
ii. | To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and |
iii. | To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement. |
(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed 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.
(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
(5)(B)(ii) That, for purposes of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness, provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
(h) Insofar as indemnification for liabilities arising under the Securities Act of 1933 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.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing onForm S-1 and has duly caused this Registration Statement onForm S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, on February 14, 2018.
ALTA MESA RESOURCES, INC. | ||
By: | /s/ Harlan H. Chappelle | |
Harlan H. Chappelle, Chief Executive officer |
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Each person whose signature appears below constitutes and appoints Harlan H. Chappelle and Michael A. McCabe, and each of them, with full power to act without the other, asattorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Commission, granting unto each saidattorney-in-fact and agent full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that saidattorneys-in-fact and agents or either 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 of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
SIGNATURE | TITLE | DATE | ||
/s/ James T. Hackett James T. Hackett | Executive Chairman of the Board and Chief Operating Officer—Midstream | February 14, 2018 | ||
/s/ Harlan H. Chappelle Harlan H. Chappelle | Chief Executive Officer and Director (Principal Executive Officer) | February 14, 2018 | ||
/s/ Michael A. McCabe Michael A. McCabe | Chief Financial Officer (Principal Financial Officer) | February 14, 2018 | ||
/s/ Ronald J. Smith Ronald J. Smith | Chief Accounting Officer (Principal Accounting Officer) | February 14, 2018 | ||
/s/ Michael E. Ellis Michael E. Ellis | Chief Operating Officer—Upstream and Director | February 14, 2018 | ||
/s/ David M. Leuschen David M. Leuschen | Director | February 14, 2018 | ||
/s/ Pierre F. Lapeyre, Jr. Pierre F. Lapeyre, Jr. | Director | February 14, 2018 | ||
/s/ William W. McMullen William W. McMullen | Director | February 14, 2018 | ||
/s/ Don Dimitrievich Don Dimitrievich | Director | February 14, 2018 | ||
/s/ William D. Gutermuth William D. Gutermuth | Director | February 14, 2018 | ||
/s/ Jeffrey H. Tepper Jeffrey H. Tepper | Director | February 14, 2018 | ||
/s/ Diana J. Walters Diana J. Walters | Director | February 14, 2018 | ||
/s/ Donald R. Sinclair Donald R. Sinclair | Director | February 14, 2018 |
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