UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K10-K/A
Amendment No. 1
(Mark One)
☒x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2019
OR
☐o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-38040
ALTA MESA RESOURCES, INC.
(Exact name of registrant as specified in its charter)
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| Delaware | 81-4433840 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
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15021 Katy Freeway, | Suite 400, | Houston, | Texas | 77094 |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: 281-530-0991281-530-0991
Securities registered pursuant to Section 12(b) of the Act: None |
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Securities registered pursuant to Section 12(b) of the Act: None |
Securities registered pursuant to Section 12(g) of the Act: None. None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☐oNo☒x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Yes ☐No☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒x No ☐o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.) Yes☒x No ☐o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-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 Rule 12b-2 of the Exchange Act. |
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| Large accelerated filer | ☐o | Accelerated filer | ☐o | Non-accelerated filer | ☐o |
| Smaller reporting company | ☒x | Emerging growth company | ☐o | | |
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 13(a) of the Exchange Act. ☐o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐o No ☒x
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 28, 2019 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $16,522,531 based on the closing price of the shares of common stock on that date.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐o No ☐o
As of January 31,February 29, 2020, there were 182,791,388182,842,867 shares of Class A Common Stock and 199,987,976 shares of Class C Common Stock, par value $0.0001 per share outstanding. The shares of Class A Common Stock shown as outstanding do not include 477,797155,196 unvested restricted stock awards outstanding as of January 31,February 29, 2020.
Portions of the registrant’s definitive Proxy Statement for its 2020 annual meeting of shareholders, which will be filed with the Securities and Exchange Commission on Schedule 14A within 120 days after the end of 2019, will be incorporated by reference into Part III of this Form 10-K to the extent indicated therein upon such filing.
Explanatory Note
Alta Mesa Resources, Inc. (the “Company”, “AMR”, “we”, “us” or “our”) is filing this Amendment No. 1 (“Amendment No. 1”) on Form 10-K/A to its Annual Report on Form 10-K for the year ended December 31, 2019 (“Form 10-K”), which was filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2020. The Company is filing this Amendment No. 1 to include the information required by Items 10-13 of Part III of our Form 10-K that was previously omitted from our Form 10-K in reliance on General Instruction G(3) to Form 10-K.
In accordance with Rule 12b-15 under the Securities and Exchange Act of 1934, as amended, new Exhibits 31.1 and 31.2 are filed herewith. This Amendment No. 1 does not amend or otherwise update any other information in our Form 10-K. Accordingly, this Amendment No. 1 should be read in conjunction with our Form 10-K. This Form 10-K/A does not reflect events that may have occurred subsequent to the filing date of our Form 10-K.
Table ofContents
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Item 1. | | |
Item 1A. | | |
Item 1B. | | |
Item 2. | | |
Item 3. | | |
Item 4. | | |
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Item 5. |
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Item 6. | | |
Item 7. | | |
Item 7A. | | |
Item 8. | | |
Item 9. | | |
Item 9A. | | |
Item 9B. | | |
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| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
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| Item 15. | | |
Item 16. | | |
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Glossary of Terms
The definitions and abbreviations set forth below apply to the indicated terms used throughout this filing.
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Company Specific Terms - | |
2018 Predecessor Period - | The period from January 1, 2018 through February 8, 2018. |
2018 Successor Period - | The period from February 9, 2018 through December 31, 2018. |
2024 Notes - | $500 million outstanding principal amount of senior unsecured notes of Alta Mesa bearing interest at 7.875%, payable semi-annually, scheduled to mature in December 2024. |
Additional Debtors - | The KFM Debtors and the SRII Debtors combined. |
Alta Mesa - | Alta Mesa Holdings, LP, which conducts our Upstream activities. |
Alta Mesa GP - | Alta Mesa Holdings GP, LLC, a majority owned subsidiary of SRII Opco, LP. |
Alta Mesa RBL - | Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, as amended. This credit agreement is a reserve based loan or RBL. |
AMH Debtors - | Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP. |
AMH PSA - | Amended & Restated Purchase and Sale Agreement by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP, as Seller and BCE-Mach III LLC, as Buyer, and Alta Mesa Resources, Inc., dated January 17, 2020. |
AMH Sale Transaction - | The expected sale by the AMH Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the AMH PSA. |
AMR - | Alta Mesa Resources, Inc. |
ARM - | ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives. |
Bankruptcy Code - | Chapter 11 of the United States Bankruptcy Code. |
Bankruptcy Court - | United States Bankruptcy Court for the Southern District of Texas. |
BCE - | BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC. |
Business Combination - | The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC. |
Buyer - | BCE-Mach III LLC. |
Debtors - | The Initial Debtors and Additional Debtors combined. |
High Mesa - | High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination. |
HMI - | High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP. |
Initial Debtors - | Alta Mesa Resources, Inc., Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP. |
KFM - | Kingfisher Midstream, LLC, which conducts our Midstream activities. |
KFM Credit Facility - | Kingfisher Midstream, LLC amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent. |
KFM Debtors - | Kingfisher Midstream, LLC, Kingfisher STACK Oil Pipeline, LLC, Oklahoma Produced Water Solutions, LLC and Cimarron Express Pipeline, LLC. |
KFM PSA - | Amended and Restated Purchase and Sale Agreement by and among Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, LLC and Cimarron Express Pipeline, LLC, as Seller, and BCE-Mach III LLC, as Buyer, dated January 17, 2020. |
KFM Sale Transaction - | The expected sale by the KFM Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the KFM PSA. |
Midstream - | Reportable business segment representing our midstream activities. |
PSAs - | The AMH PSA and KFM PSA combined. |
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PSU's - | Performance-based restricted stock units issued to employees under the Alta Mesa Resources, Inc. 2018 Long-Term Incentive Plan. |
Riverstone Contributor - | Riverstone VI Alta Mesa Holdings, L.P. |
Sale Transactions - | The AMH Sale Transaction and KFM Sale Transaction combined. |
Sponsor - | Silver Run Sponsor II, LLC. |
SRII Debtors - | SRII Opco, LP and SRII Opco GP, LLC. |
SRII Opco - | SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC. |
Tax Receivable Agreement - | Tax Receivable Agreement dated as of February 9, 2018, among Alta Mesa Resources, Inc., SRII Opco, LP, Riverstone VI Alta Mesa Holdings, L.P., and High Mesa Holdings LP. |
Upstream - | Reportable business segment representing our exploration and production activities. |
Wind down - | This represents the post-sale activities to conclude the affairs of the Company, including final settlement of the Company's estate. |
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Oil, Gas and Other Terms - | |
3D 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 than two-dimensional seismic data. |
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 to describe volumes of crude oil, condensate or natural gas liquids. |
bbld - | Barrels per day. |
Bcf - | One billion cubic feet of natural gas. |
Bcfe - | One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids. |
Boe - | One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio of energy content between natural gas and oil, and does not represent the price equivalency of natural gas to oil or natural gas liquids. |
Boed - | 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. |
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 the natural gas stream. |
DD&A - | Depreciation, depletion and amortization. |
Developed acreage - | The number of acres that are allocated or assignable to productive wells or wells capable of production. |
Developed reserves - | Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well. |
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. |
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. |
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Differential - | An adjustment to the market reference 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. |
Dry hole - | A well found to be incapable of producing hydrocarbons in commercial quantities. |
Dry hole costs - | Costs incurred in drilling an unsuccessful exploratory well, including plugging and abandonment costs. |
Dth - | A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu. |
Dthd - | 1,000,000 Btu per day. |
EBITDA - | Earnings before interest, taxes, depreciation, depletion and amortization. |
EBITDAX - | Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses. |
Exploratory well - | A well drilled to find a new field or to find a new 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. |
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 adjacent rock. |
Fracing, fracture stimulation technology, hydraulic fracturing - | A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation. |
Gross acres or gross wells - | The total acres or wells in which a working interest is owned. |
Held by production - | Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum economic quantity of production. |
Horizontal drilling - | A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. |
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 well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses. |
Mbbl - | One thousand barrels of crude oil, condensate, natural gas liquids, or produced water. |
Mbbld - | One thousand barrels per day. |
MBoe - | One thousand Boe. |
MBoed - | One thousand Boe per day. |
Mcf - | One thousand cubic feet of natural gas. |
Mcfd - | One thousand cubic feet per day. |
Mcfe - | One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas. |
Mcfed - | Mcfe per day. |
MMBoe - | One million boe. |
MMBtu - | One million British thermal units. |
MMBtud - | One million British thermal units per day. |
MMcf - | One million cubic feet of natural gas. |
MMcfd - | One million cubic feet per day. |
MMcfe - | 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. |
MMcfed - | MMcfe per day. |
MMBbl - | One million barrels of crude oil, condensate or natural gas liquids. |
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Net acres - | The total acres a working interest owner has attributable to a particular number of acres, or a specified tract. |
Net production - | Portion of production owned by us after production attributable to royalty and other owners. |
Net revenue interest - | A working interest owner’s working interest in production after deducting royalty, overriding royalty, production payments and net profits interests. |
NGLs or
natural gas liquids - | Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline. |
Non-operated working interests - | The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement. |
NYMEX - | The New York Mercantile Exchange. |
P&A - | Plug and Abandonment (P&A) is the permanent dismantlement and removal of production equipment and facilities from service at the end of an asset’s economic life. |
PDNP - | Proved developed non-producing reserves. |
PDP - | Proved developed producing reserves. |
Produced water - | Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs. |
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. |
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 - | Quantities of oil and natural gas, which can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations. |
Proved undeveloped reserves ("PUD") - | Reserves that are expected to be recovered from new wells, or from existing wellbores where a relatively major expenditure is required to make the well producible. |
PV-10 - | 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 to non-property related expenses, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“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 revenue. Neither PV-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 PV-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. |
Realized price - | The cash market price less all expected quality, transportation and demand adjustments. |
Reserves - | Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations. |
Reservoir - | A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs. |
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. |
SEC - | United States Securities and Exchange Commission. |
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, produced water disposal, water supply for injection, observation, or injection for in-situ combustion. |
Spacing - | The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies. |
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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 - | Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%. |
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. |
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. Also, the area covered by a unitization agreement. |
Unproved properties - | Properties with no proved reserves. |
VWAP - | Volume weighted average price. |
Wellbore - | The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called a 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. |
Workover - | Operations on a producing well to restore or increase production. |
Cautionary Statement Regarding Forward-Looking Statements
The information in this Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could”, “should”, “will”, “plan”, “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.
Forward-looking statements may include statements about:
the expected closing of the Sale Transactions;
our expectations of outcomes in our bankruptcy proceedings;
our ability to fulfill the transition services agreement with the buyer of our assets;
our ability to continue as a going concern;
our ability to comply with the requirements imposed by our bankruptcy process;
our business strategy;
our reserve quantities and the present value of our reserves;
our exploration and drilling prospects, inventories, projects and programs;
our drilling, completion and production technology;
our ability to replace the reserves we produce through drilling and through acquisitions;
future oil and gas prices;
the supply and demand for our production and our midstream services;
the timing and amount of our future production;
competition and government regulation;
our ability to obtain permits and governmental approvals;
our future drilling plans, spacing plans and development pace;
our marketing of our production;
our access to capital, including constraints from the cost and availability of debt and equity financing;
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 production levels, initial production rates and yields in our type curve areas;
the costs, terms and availability of midstream services;
pending legal and environmental matters;
our ability to retain qualified personnel during our wind-down period and the sufficiency of resources to conduct the wind down;
general economic conditions;
our plans, objectives, expectations and intentions contained in this Annual Report that are not historical; and
our ability to collect receivables from High Mesa, Inc. and its subsidiaries.
We caution you that any 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. 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 Buyer’s ability and willingness to close the Sale Transactions, orders by the Bankruptcy Court that impact the ability to fund and conduct our operations, liabilities resulting from litigation or the SEC investigation, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and 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, cyber-attacks, title defects, limited control over non-operated properties, our ability to satisfy future cash obligations, restrictions in our debt agreements, and the other risks with the wind down of our operations.
Estimating quantities of oil, natural gas and NGL reserves is complex and inexact. The process relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires a number of economic assumptions, such as oil, natural gas and NGL prices, the relative mix of oil,
natural gas and NGLs that will be ultimately produced, drilling and operating expenses, capital expenditures, the effect of government regulation, taxes and availability of funds. 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.
Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
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 occurring after the date of this Annual Report.
PART IIII
Item 1. Business10. Directors, Executive Officers and Corporate Governance
Alta Mesa Resources, Inc. (“AMR”)We currently have nine directors. James T. Hackett, Don Dimitrievich and William W. McMullen serve as Class III directors, with terms expiring at the 2020 Annual Meeting; Sylvia J. Kerrigan, David M. Leuschen and Donald R. Sinclair serve as Class I directors, with terms expiring at the Company's annual meeting of stockholders in 2021; and Pierre F. Lapeyre, Jr., togetherJeffrey H. Tepper and Diana J. Walters serve as Class II directors, with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused onterms expiring at the developmentCompany’s annual meeting of unconventional onshore oil and natural gas reservesstockholders in 2022. Of our nine board members, four are elected by the eastern portionholders of the Anadarko Basin in Oklahoma. We operate inClass A Common Stock, two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an areaare elected by the holders of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principallySeries A Preferred Stock and three are elected by the productionholders of Series B Preferred Stock.
AMR and saleits upstream subsidiaries expect to file a plan of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts. Our principal offices are at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 and our main phone number is (281) 530-0991.
We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the IPO and a private sale of warrants were placed in a trust account and were used on February 9, 2018, to acquire the interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination” at which time we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.
On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for reliefliquidation under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).
On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.
The Initial and Additional Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).
The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled. In the event all outstanding shares of class A common stock and class C common stock are canceled, we will not hold a 2020 Annual Meeting.
James T. Hackett’s term as a Class III director to the Board will be subject to approvalexpire at the 2020 Annual Meeting unless he is reelected by the Bankruptcy Courtaffirmative vote of the holder of our Series B Preferred Stock. The terms of Don Dimitrievich and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuantWilliam W. McMullen as Class III directors to the requirementsBoard will expire at the 2020 Annual Meeting unless they are each reelected by the affirmative vote of the Bankruptcy Code.holder of our Series A Preferred Stock. We expect the Bankruptcy Courtbelieve these directors will continue to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent thatserve until the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.
In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.
The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.
Our Class A Common Stock and public warrants to purchase Class A Common Stock, sold as part of the shares issued in the IPO, were initially traded on the NASDAQ Capital Market (“NASDAQ”), but due to our failure to continue to meet the NASDAQ’s listing requirements, trading in our stock and public warrants was suspended in September 2019, and are now traded over the counter on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Accordingly, we do not anticipate filing any additional current, quarterly or annual reports with the SEC.
Going Concern
AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.
We expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.
Organizational Structure
The following diagram illustrates our ownership structure as of December 31, 2019.
Business Combination
As described further in Item 8 of this Annual Report, the Business Combination was consummated on February 9, 2018, that resulted in our acquisition of interests in Alta Mesa, Alta Mesa GP and KFM through a newly formed subsidiary, SRII Opco. Prior to the Business Combination, Alta Mesa was controlled by High Mesa, Inc. (“HMI”).
Immediately prior to the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (“High Mesa”), such that Alta Mesa’s only remaining oil and gas assets and liabilities were located in the STACK. As described elsewhere, High Mesa owes us a substantial sum for amounts arising before and after the Business Combination, and it had indemnified us for liabilities arising from non-STACK oil and gas assets. We believe there is substantial doubt about its ability to make payment and honor its indemnification given HMI’s filing for bankruptcy protection in January 2020. Information related to Alta Mesa’s non-STACK oil and gas assets and liabilities that were sold or distributed is disclosed as discontinued operations in Item 8 of this Annual Report.
Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values and pushed those values down to the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods - the period before the Business Combination on February 9, 2018 (“Predecessor”) and the period after the Business Combination (“Successor”).
Principal Products, Markets and Customers
Our Upstream segment sells our production of oil, natural gas and NGLs to customers generally at prevailing spot prices in effect at the time of the sale. Our Midstream segment derives its revenue from fees assessed for gathering and processing natural gas, gathering and transporting oil, the sale of processed residue gas and NGLs and produced water gathering and disposal services. Natural gas is processed on behalf of the producer and the resulting gas, condensate and NGLs are sold at market prices. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. Collateral or other security is generally not required with regard to our trade receivables.
During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed our oil, gas and NGLs for a marketing fee that was deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. In June 2019, we terminated our oil and NGL marketing agreement with ARM and began marketing such products internally.
For 2019, ARM marketed $123.0 million, or 24.6% of our total operating revenue for the period.
Other than our natural gas marketing agreement with ARM, we had one customer, Phillips 66, that accounted for $202.6 million, or 40.5% of our total operating revenue for 2019.
Seasonality
Weather conditions affect the demand for, and prices of, oil and gas. During the winter, natural gas demand for heating by residential and commercial consumers generally increases whereas high summer temperatures can result in an increase in demand from the power sector. Natural gas in storage typically increases from April through October. Crude oil markets tend to be stronger in the fourth quarter when demand for heating oil is impacted by colder weather and inventory build. Hurricanes and other severe weather (particularly along the Gulf Coast) can also impact supplies by causing disruptions in the level of oil and gas production. Due to these fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Competition
We compete with other companies in all areas of our operations, including, in the past, the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies and independent oil and gas companies. Many of our competitors are large, well-established companies with substantially greater resources and better credit than us and have been engaged in the oil and gas business for a longer period of time than we have. Our filings for bankruptcy protection and restrictions placed on our spending by the Bankruptcy Court have also put us at a competitive disadvantage. This may allow our competitors to have an advantage over us with respect to:
maintaining production levels on existing oil and gas properties;
evaluations of properties;
utilization of midstream assets; and
absorption of price changes and the costs and implementation of evolving federal, state and local laws and regulations.
In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe, materials (including drilling and completion fluids) and personnel. We are unable to predict when, or if, such future shortages will occur or their impact on our operations.
Regulatory Environment
Our Upstream and Midstream 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 U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Among other things, these laws and regulations may:
require various permits before drilling and other regulated activities commence;
require installation of pollution control equipment and place other conditions on our operations;
place restrictions on the use of materials for our operations and upon the disposal of by-products from our operations;
restrict the types, quantities and concentrations of various substances that can be released into the environment or used for our operations;
limit our operations 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 obligations.
Resource Conservation and Recovery Act
The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-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. As part of our operations, we generate some amounts of ordinary industrial wastes that may be deemed as hazardous wastes by regulatory authorities. Drilling fluids, produced waters, and most of the other wastes associated with our operations, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that regulations could change and cause wastes now classified as non-hazardous to be classified as hazardous wastes.
Comprehensive Environmental Response, Compensation and Liability Act
The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability on classes of persons considered to be responsible for the release of hazardous substances and other classes of materials. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for damages without regard to fault or legality of the original conduct. These classes of persons, referred to as 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 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 statutes.
Federal Water Pollution Control Act
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state and federal waters. 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.
Safe Drinking Water Act
Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state and local laws and regulations. The UIC program includes administrative requirements for produced water disposal and prohibits migration of fluid containing any contaminant into underground sources of drinking water. State regulations require permits 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 produced water disposal wells, federal and some state agencies are investigating whether such wells have contributed to 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.
National Environmental Policy Act
Our operations on federal lands may be subject to the federal National Environmental Policy Act (“NEPA”), which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. As part of such evaluations, an agency will conduct an environmental assessment that assesses the potential impacts of a proposed project and may require the preparation of a detailed environmental impact statement for public review and comment. Our current and future operations on federal lands will be subject to NEPA, which could delay or impose additional conditions and costs on us. Moreover, this process could involve protest, appeal or litigation, any or all of which may impact our operations.
Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes enacted to protect the health and safety of workers. In addition, comparable state statutes require that we organize and/or disclose information about hazardous materials attendant to our operations to our employees, state and local governmental authorities and citizens.
Our processing plant operations are also subject to standards designed to ensure the safety of our processes, such as the Occupational Safety and Health Administration’s Process Safety Management standard, which is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The Process Safety Management standard imposes requirements on regulated entities related to managing these hazards. These requirements include conducting process hazard analyses for processes involving highly hazardous chemicals, developing detailed written operating procedures, including procedures for managing change, and evaluating the mechanical integrity of critical equipment. We conduct periodic audits of Process Safety Management systems at each of our locations subject to this standard.
Hydraulic Fracturing
We perform hydraulic fracturing in horizontally drilled wells. Currently, most of our hydraulic fracturing activities are regulated at the state level, given that the EPA only has limited authority to regulate fracturing activities. 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 into surface waters; and disposal or storage of fracturing wastewater in unlined pits.
Clean Air Act
Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of air pollutants. These laws and regulations may require us to obtain approval for the construction or modification of certain facilities expected to produce or significantly increase air emissions, comply with stringent air permitting requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our operations.
Climate Change Regulations 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 all levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-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 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 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 directly regulate emissions of methane, a GHG, from oil and gas operations. In August 2016, the EPA issued a final New Source Performance Standards (“NSPS”) rule, known as Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expanded the previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of volatile organic compounds in general). Future implementation of this rule is uncertain at this time.
Other Regulation of the Oil and Gas Industry
Our operations are also subject to various other types of regulation at the federal, state and local level. These types of regulations include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate may also regulate:
the location of wells;
the method of drilling and casing wells;
the timing of conducting our activities, including seasonal wildlife closures;
the rates of production;
the surface use and restoration of properties where we operate;
the plugging and abandoning of wells;
interactions with surface owners and other third parties; and
abandonment of pipelines and midstream facilities.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. We rely upon the Oklahoma “forced pooling” process to facilitate working interest owners’ participation in our operations. Under this process, 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 gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may initiate “forced pooling”. Under current regulations, drilling and spacing units for our targeted horizons are based on a maximum of four to eight horizontal wells, depending on the formation, on a 640-acre section. In a forced pooling action, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair value of the mineral interests in the unit is determined in an administrative proceeding by reference to market transactions involving nearby oil and gas rights, including nearby mineral lease costs.
Assuming the application for a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair value for their interest, usually in the form of a cash payment, an overriding royalty, or some
combination, based on the fair value established and approved through the administrative hearing. The pooling order typically 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 normally means that it is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Oil and gas companies in Oklahoma generally attempt 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.
The gross production tax, or severance tax, is a value-based tax levied at a basic rate of 7% upon the production of oil and gas in Oklahoma. As an economic incentive to develop its resources, Oklahoma has historically offered a “tax holiday” with rates ranging from 1% for 48 months to 2% for 36 months for production from horizontal wells. Through June 2018, Oklahoma imposed a tax of 2% of gross production for the first 36 months of production and then at 7% thereafter on wells drilled after July 1, 2015. Effective July 2018, the 2% tax rate was increased to 5% for wells drilled after July 1, 2015 that were still within their first 36 months of production. For the period beyond 36 months, the tax rate remains at 7% for the remaining productive life of each well. All wells drilled after July 1, 2018 are taxed at 5% of gross production for the first 36 months of production and then at 7% thereafter. In addition, a longstanding excise tax of 0.095% continues to be levied.
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 U.S. Army Corps of Engineers and many other state and local authorities also have regulations covering these procedures. Some state agencies and municipalities have binding requirements related thereto.
Regulation of Natural Gas Sales and Transportation
The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the Federal Energy Regulatory Commission (the “FERC”), as common carriers, under the Interstate Commerce Act. The 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.
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, 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. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety.
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 Parts 171-180, 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.
Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our Midstream assets meet the tests the FERC has used to determine exemption from its jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.
Other
The oil and gas industry is also subject to other federal, state and local regulations and laws relating to resource conservation and employment standards.
Employees
As of December 31, 2019, we had 151 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.
Insurance
We maintain customary insurance against some, but not all, of the operating risks to which our business is exposed such as general liability (includes sudden and accidental pollution), physical damage to our assets, control of wells, auto liability, worker’s compensation and employer’s liability.
We regularly execute master services contracts with our third-party vendors, suppliers and contractors in which they agree to indemnify us for injuries and deaths of their employees and contractors. Similarly, we generally agree to indemnify them against claims made by our other vendors, suppliers, contractors and employees. Additionally, each party is generally responsible for damage to its own property.
Available Information
We disseminate information about the Company through required filings we make with the SEC and, at our discretion, on our website at www.altamesa.net. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Accordingly, we do not anticipate filing any additional current, quarterly or annual reports with the SEC.
Information contained on or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or any other filings we make with the SEC. The SEC maintains a site that contains reports, proxy and information statements and other information regarding reporting issuers. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K are filed electronically and are available free of charge at http://www.sec.gov. Additionally, the Company will provide electronic or paper copies free of charge upon request to our Secretary at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 or by calling (281) 530-0991.
Item 1A. Risk Factors
Not required.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties
Upstream Segment
Overview
As of December 31, 2019, we held a highly contiguous position of approximately 127,100 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher and south-eastern Major Counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.
At December 31, 2019, we had an average 66% net working interest in 814 gross producing wells.
After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the expected well level production. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section and began operating 2 rigs, however following our filing for bankruptcy protection in September 2019, we discontinued further development activities.
Bayou City Joint Development Agreement
In January 2016, we entered into a joint development agreement (as subsequently amended, the “JDA”) with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Management, LLC, to fund a portion of our drilling operations with the intent to accelerate our development. The JDA established a development plan of 60 wells in three tranches, and provided opportunities for the parties to potentially agree to an additional 20 wells. As of December 31, 2019, 61 joint wells had been drilled or spudded.
Under the JDA, up to 100% of our well costs could be funded up to a specified total well cost. In exchange for BCE carrying the drilling and completion costs, they received 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.
During the 2018 Successor Period, we brought 25 horizontal wells on production that were funded through the JDA. At December 31, 2019, there were no JDA wells in progress, and none have been developed in 2020. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves. The JDA expired in January 2020 pursuant to its terms.
Our Oil and Gas Reserves
Our proved reserves and production profile as of December 31, 2019 was as follows:
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| Total Estimated Proved Reserves (MMBoe) | | Percent Proved Developed | | PV-10 ($ in millions)(1) | | Standardized Measure ($ in millions)(1) | | Net Producing Wells(2) | | Average 2019 Daily Net Production (MBoe/d) |
| 46.5 | | 100% | | $346.3 | | $326.9 | | 535 | | 35.0 |
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(1) | PV-10 is a non-GAAP measure of the estimated future net cash flows from proved reserves before giving effect to income taxes, discounted at an annual rate of 10 percent. The calculation of PV-10 also does not give effect to potential derivatives or hedging transactions. Standardized measure is the after-tax estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent and may (depending upon a registrant’s derivative and hedging policy) include the effects of hedges, all determined in accordance with GAAP. We believe PV-10 is a useful measure of the value of our proved reserves because it allows users of our financial statements to compare relative values and sizes of proved reserves among exploration and production companies without regard to their corporate structure and the resulting income tax burden. The difference between PV-10 and standardized measure is the discounted effect of income taxes, totaling $19.4 million, on our share of expected future net cash flows, without taking into consideration the utilization of net operating loss carryforwards. |
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(2) | Calculated as gross wells multiplied by our working interest percentage for each well. |
Key information and assumptions used in determining our estimated net proved reserves at the end of each period is set forth in Item 8. All of our reserves are located in the United States.
|
| | | | | | | | | | | | |
| Oil and NGLS (Mbbls) | | | | | | |
| | Successor | | | Predecessor |
| | December 31, 2019 | | December 31, 2018 | | | February 8, 2018 |
Proved Reserves (1) | | | | | | |
| Developed | 27,431 |
| | 45,064 |
| | | 30,693 |
|
| Undeveloped | — |
| | — |
| | | 77,256 |
|
| Total | 27,431 |
| | 45,064 |
| | | 107,949 |
|
Average market prices (per bbl) - oil(2) | $ | 55.69 |
| | $ | 65.56 |
| | | $ | 52.89 |
|
Average realized prices (per bbl) - NGLs(2) | $ | 14.60 |
| | $ | 22.44 |
| | | $ | 27.48 |
|
|
| | | | | | | | | | | | |
| Natural Gas (MMcf) | | | | | | |
| | Successor | | | Predecessor |
| | December 31, 2019 | | December 31, 2018 | | | February 8, 2018 |
Proved Reserves (1) | | | | | | |
| Developed | 114,443 |
| | 144,148 |
| | | 126,231 |
|
| Undeveloped | — |
| | — |
| | | 284,571 |
|
| Total | 114,443 |
| | 144,148 |
| | | 410,802 |
|
Average market prices (per MMBtu) - natural gas(2) | $ | 2.58 |
| | $ | 3.10 |
| | | $ | 2.99 |
|
|
| | | | | | | | | |
| Total (MBoe) | | | | | | |
| | Successor | | | Predecessor |
| | December 31, 2019 | | December 31, 2018 | | | February 8, 2018 |
Proved Reserves (1) | | | | | | |
| Developed | 46,505 |
| | 69,089 |
| | | 51,731 |
|
| Undeveloped | — |
| | — |
| | | 124,685 |
|
| Total | 46,505 |
| | 69,089 |
| | | 176,416 |
|
_________________
| |
(1) | Proved reserves were calculated using oil and gas parameters established by current SEC guidelines and accounting rules. Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and gas prices, revenue, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary from these estimates. In addition, we may adjust our estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. |
| |
(2) | Average market prices represent an unweighted arithmetic average of the market price on the first day of each month during the last 12 months. |
Proved Undeveloped Reserves
Based on Alta Mesa’s bankruptcy filing and/or our inability to fund development costs, we did not recognize any PUDs as of December 31, 2019 and 2018. The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations. Changes in our proved undeveloped reserves during the 2018 Successor Period and the 2018 Predecessor Period were (in MBoe):
|
| | | | | | | | | |
| | Successor | | | Predecessor |
| | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Beginning of period | — |
| | 124,685 |
| | | 125,101 |
|
| Converted into proved developed reserves | — |
| | (18,999 | ) | | | — |
|
| Extensions and discoveries | — |
| | 43,354 |
| | | — |
|
| Reserves acquired | — |
| | 3,738 |
| | | — |
|
Reserves sold/distributed(1) | — |
| | — |
| | | (1,129 | ) |
Revisions(2) | — |
| | (152,778 | ) | | | 713 |
|
| End of period | — |
| | — |
| | | 124,685 |
|
| | | | | | | |
| Percentage of total proved reserves | — | % | | — | % | | | 71 | % |
_________________
| |
(1) | Reserves sold/distributed during the period January 1, 2018 to February 8, 2018, represent amounts related to our non-STACK properties that are classified as discontinued operations in our financial statements. |
| |
(2) | Effective as of December 31, 2018, due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we removed all of our PUDs from our total estimated proved reserves. |
During 2019, we did not incur any expenses to develop PUD reserves, compared to approximately $160.6 million incurred during the 2018 Successor Period. PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of their recognition. As a result of Alta Mesa’s bankruptcy filing and the expected Sale Transactions, we do not expect to incur any further development of our properties. Thus, we have concluded that we do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our available drilling locations.
Internal Controls Over Reserve Estimates and Qualifications of Technical Persons
Our policies and practices regarding internal controls over reserve recognition are structured to objectively and accurately estimate our oil and gas reserves quantities and their present value in compliance with SEC standards. The reserve estimation process begins with our Corporate Reserves department, which gathers and analyzes much of the data used as inputs to estimating reserves. Working and net revenue interests are sourced from our division order system in our land department. Lease operating expenses are provided by our accounting department and our operations team provides capital expenses. Our Vice President of 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; and
Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Master of Business Administration from Oklahoma City University in 1988.
Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and volumetric analysis, with performance methods preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on analogy to offset production in the same area.
We maintain internal controls that we believe result in the proper amount and value of our reported reserves. These controls, which we determined to be effective for all periods presented, include:
we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;
reserve estimates are made by experienced reservoir engineers or under their direct supervision; and
annually, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and new proved undeveloped reserves additions.
Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 97% of our 2019 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.
Miles R. Palke with Ryder Scott earned a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and a Master of Science in Petroleum Engineering from Stanford University in Palo Alto California. Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas. Based on his educational background, professional training and more than 23 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke 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.
A reserves audit and a financial audit are separate activities with unique and different processes and results. A reserves audit under SEC standards 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.
Oil and Gas Production, Production Prices and Production Costs
Information relating to our oil and gas production, sales prices for our products produced and production costs is included in Item 7.
Drilling and Other Exploratory and Development Activities
|
| | | | | | | | | |
| | Successor | | | Predecessor |
| | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Development wells drilled (net): | | | | | | |
| Productive | 48.8 |
| | 123.8 |
| | | 7.0 |
|
| Dry | — |
| | — |
| | | — |
|
| Total development wells | 48.8 |
| | 123.8 |
| | | 7.0 |
|
| | | | | | | |
| Exploratory wells drilled (net): | | | | | | |
| Productive | — |
| | — |
| | | — |
|
| Dry | — |
| | 1.0 |
| | | — |
|
| Total exploratory wells | — |
| | 1.0 |
| | | — |
|
Activities at Year End
At December 31, 2019, we had no wells that were in progress for drilling or completion operations.
Delivery Commitments
Information about our firm transportation commitments is included in Part II, Item 8.
Productive Wells, Developed and Undeveloped Acreage
The following sets forth information with respect to our wells and acreage under lease as of December 31, 2019, all of which is located in the United States:
|
| | | | | |
| | December 31, 2019 |
| | Gross | | Net |
Number of producing wells principally targeting (1): | | | |
| Oil | 792 |
| | 521.8 |
|
| Gas | 22 |
| | 13.2 |
|
| Total wells | 814 |
| | 535 |
|
| | | | |
| Properties: | | | |
| Developed acres | 176,455 |
| | 110,412 |
|
| Undeveloped acres | 39,085 |
| | 16,647 |
|
| Total acres | 215,540 |
| | 127,059 |
|
| | | | |
Undeveloped acreage expirations (2): | | | |
| Year ending December 31, 2020 | 11,301 |
| | 4,504 |
|
| Year ending December 31, 2021 | 17,428 |
| | 5,969 |
|
| Total | 28,729 |
| | 10,473 |
|
_________________
| |
(1) | 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, including joint development wells. |
| |
(2) | Our lease acreage is typically subject to expirations if a well is not drilled and producing before the end of the primary term. The primary term of our leasehold ranges from 3 to 5 years. As is customary in our industry, our undeveloped leasehold may be maintained through: (i) commencing operations for drilling, completion and production, (ii) pooling, (iii) extensions or renewals and (iv) other operational extensions, including shut-in payments and continuous operations. |
Title to Properties
We typically conduct a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, at the time we acquire properties. We believe that title to our interests is satisfactory and consistent with the standards in our industry.
Midstream Segment
Our KFM assets include a gas and oil gathering network, a cryogenic gas processing plant with off-take capacity, field compression facilities and a produced water disposal system. These assets are located in the Anadarko Basin in Oklahoma.
KFM expanded its gas gathering system northward into Major County, Oklahoma, with a high-pressure line to connect the existing system in Kingfisher County, Oklahoma to new low-pressure gathering pipelines in southeastern Major County.
Prior to November 2019, KFM held a 50% equity interest in a partnership to develop a long-haul crude oil pipeline project, the Cimarron Express Pipeline (“Cimarron”), that was designed to link the existing crude oil storage tank located at the KFM Lincoln Terminal to a crude oil terminal site at Cushing, Oklahoma. Based on lower oil prices, less development wells and lower expected volumes from new wells, we determined in the fourth quarter of 2018 that the project was not likely to be completed and recognized an impairment to reduce our investment to its estimated fair value at December 31, 2018. In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. Following this transaction, Cimarron became our wholly owned subsidiary.
In November 2018, Alta Mesa sold substantially all of its produced water assets to a subsidiary of KFM, consisting of over 200 miles of produced pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations.
Item 3. Legal Proceedings
We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur,
assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The commencement of the Chapter 11 proceedings automatically stayed most of these actions against the Company.
Bankruptcy
On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).Texas.
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Chairman of the Board of Alta Mesa Resources, Inc. (February 2020 - Present), Executive Chairman of the Board of Alta Mesa Resources, Inc. (February 2018-February 2020) and Interim Chief Executive Officer of Alta Mesa Resources, Inc. (December 2018 - September 2019) |
| ● | Chief Operating Officer—Kingfisher Midstream, LLC (February 2018 - April 2018) and the CEO and President—Kingfisher Midstream, LLC (May 2018 - September 2019) |
| ● | Senior Advisor and former Partner with Riverstone Holdings LLC, a private energy investment firm (2013 - 2020) |
| ● | Chairman of the Board (2006 - 2013) and Chief Executive Officer (2003 - 2012) of Anadarko Petroleum Corporation |
| ● | Chairman of the Board of the Federal Reserve Bank of Dallas (2004 - 2006) |
| James T. Hackett | | ● | President and Chief Operating Officer of Devon Energy Corporation (2003) |
| Chairman of the Board | | ● | Chairman, President, and Chief Executive Officer of Ocean Energy and its predecessor Company, Seagull Energy (1998 - 2003) |
| Age: 66 | | ● | President of Energy Services Group at Duke Energy Corporation and Executive VP at PanEnergy Corp. (1996 - 1998) |
| Class III Director | CURRENT PUBLIC COMPANY BOARDS |
| | ● | Director of Fluor Corporation (NYSE: FLR) |
| | ● | Director of National Oilwell Varco, Inc. (NYSE: NOV) |
| | ● | Director of Enterprise Products Holdings, LLC (NYSE: EPD) |
| OTHER POSITIONS |
| | ● | Director of Talen Energy Corporation |
| | ● | Member of Rice University and Baylor College of Medicine Trustees (and former Chairman of the latter) |
| | ● | Faculty member at University of Texas at Austin and Rice University |
| EDUCATION |
| | ● | Bachelor of Science, University of Illinois |
| | ● | MBA and MTS degrees from Harvard University |
| | | |
| Mr. Hackett was selected to serve on the Board due to his significant leadership experience and his extensive experience in the energy industry. |
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Skadden, Arps, Slate, Meagher & Flom LLP (1998 - 2004) |
| ● | Managing Director of Citi Credit Opportunities |
| OTHER POSITIONS |
| ● | Managing Director at HPS Investment Partners (2012-present) |
| ● | Director of Montage Resources Corporation |
| ● | Director Expro International Group Holdings Ltd. |
| ● | Director Glacier Oil & Gas Corp. |
| ● | Director Marquis Resources, LLC |
| Don Dimitrievich | EDUCATION |
| Director since 2018 | | ● | Law Degree magna cum laude, McGill University in Montreal, Canada |
| Age: 48 | | ● | Chemical Engineering degree, Queen’s University in Kingston, Canada |
| Class III Director | | | |
| Mr. Dimitrievich was selected to serve on the Board due to his significant mergers and acquisitions, financing and investing experience in the energy industry. |
|
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Manager of Bayou City Energy Partners (April 2014-present) |
| ● | Vice President at White Deer Energy (June 2012-October 2014) |
| ● | Associate at Denham Capital (June 2010-June 2012) |
| ● | Analyst in UBS Investment Bank’s Global Energy group (July 2008-June 2010) |
| OTHER POSITIONS |
| ● | Founder and Managing Partner of Bayou City Energy Partners (January 2015-present) |
| ● | Director WKP I LLC |
| ● | Director BCE-Mach LLC |
| William W. McMullen | | ● | Director BCE-Mach II LLC |
| Director since 2018 | | ● | Director BCE-Mach III LLC |
| Age: 34 | EDUCATION |
| Class III Director | | ● | Bachelor’s degree in Economics, with Honors, from Harvard University. |
| | | |
| Mr. McMullen was selected to serve on the Board due to his broad knowledge of, and experience with, oil and gas investments. |
|
|
Our Class I and Class II directors are listed below.
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Senior management and operating roles at Gleacher & Company, Inc. (1990 - 2013) |
| ● | Co-founder and President of Gleacher & Company, Inc's asset management activities (2001) |
| ● | Managing Director of and Chief Operating Officer of Gleacher NatWest Inc. (1997 - 1999) |
| ● | M&A Financial Analyst for Morgan Stanley & Co. (1987 - 1990) |
| CURRENT PUBLIC COMPANY BOARDS |
| ● | Director of Centennial Resource Development, Inc. (NASDAQ: CDEV) |
| OTHER POSITIONS |
| ● | Founder of JHT Advisors LLC (March 2017 - present) |
| Jeffrey H. Tepper | EDUCATION |
| Director since 2017 | | ● | MBA from Columbia Business School |
| Age: 54 | | ● | B.S. in Economics from The Wharton School of the University of Pennsylvania |
| Class II Director | | | |
| Mr. Tepper was selected to serve on the Board due to his significant investment and financial experience. |
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | President of Liberty Metals & Mining Holdings, LLC (2010 - 2014) |
| ● | Managing Partner of Eland Capital, LLC (2007 - 2010) |
| CURRENT PUBLIC COMPANY BOARDS |
| ● | Platinum Group Metals (NYSE: PLG) |
| ● | Trilogy Metals Inc. (NYSE: TMQ) |
| ● | Atmos Energy Corporation (NYSE: ATO) |
| OTHER POSITIONS |
| ● | Owner and sole manager of AMICHEL, LLC (2019 - present) |
| ● | Previous owner and sole manager of 575 Grant, LLC (2014 - 2019) |
| Diana J. Walters | EDUCATION |
| Director since 2017 | | ● | B.A. in Plan II Liberal Arts from University of Texas at Austin |
| Age: 56 | | ● | M.A. in Energy and Mineral Resources from University of Texas at Austin |
| Class II Director | |
| Ms. Walters was selected to serve on the Board due to her significant investment and operating experience in the energy industry. |
|
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Managing Director of Goldman Sachs (1998-2000) |
| CURRENT PUBLIC COMPANY BOARDS |
| ● | Non-executive board member of Riverstone Energy Limited (LSE: REL) |
| ● | Non-executive board member of Centennial Resource Development, Inc. |
| OTHER POSITIONS |
| ● | Founder of Riverstone Holdings LLC and Senior Managing Director (2000-present) |
| ● | Member of the Executive Committee of the Board of Visitors of The University of Texas MD Anderson Cancer Center |
| ● | Treasurer, Chair of the Investment Committee (Endowment) and member of the Finance Committee and Pension Committee at the Convent of the Sacred Heart. |
| Pierre F. Lapeyre, Jr. | | ● | Director of boards or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates |
| Director since 2018 | EDUCATION |
| Age: 57 | | ● | MBA from the University of North Carolina at Chapel Hill |
| Class II Director | | ● | B.S. in Finance and Economics from the University of Kentucky |
| | | |
| Mr. Lapeyre was selected to serve on the Board due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry. |
|
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Executive Vice President, General Counsel and Secretary of Marathon Oil Corporation (2012 - 2017) |
| ● | Chief Public Policy Officer of Marathon (2014 - 2017) |
| ● | Chief Compliance Officer of Marathon (2013- 2017) |
| ● | Vice President, General Counsel and Secretary of Marathon (2009 - 2012) |
| ● | United Nations Security Council’s Commission d’Indemnisation in Geneva, Switzerland serving as their senior legal officer (2000 - 2001) |
| CURRENT PUBLIC COMPANY BOARDS |
| ● | Director of Team, Inc. (NYSE: TISI), where she sits on the Audit Committee and Corporate Governance and Nominations Committee |
| Sylvia J. Kerrigan | OTHER POSITIONS |
| Director since 2018 | | ● | Director for Nine Point Energy, where she is the Chair of the Audit Committee and sits on the Compensation Committee. |
| Age: 54 | | ● | Board of Trustees for Southwestern University |
| Class I Director | | ● | Executive Director and Executive Council of the Kay Bailey Hutchison Center for Energy, Law and Business at the University of Texas in Austin |
| EDUCATION |
| | ● | J.D. from the University of Texas at Austin School of Law |
| | ● | B.A. from Southwestern University, concentrating in philosophy, political economy and English |
| | | |
| Ms. Kerrigan was selected to serve on the Board due to her experience as chief legal officer, chief public policy officer and chief compliance officer of a public corporation, and her extensive merger and acquisition, risk management and corporate governance expertise. |
|
|
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Partner and Managing Director of Goldman Sachs (1986 - 2000) |
| ● | Founder and head of the Goldman Sachs Global Energy and Power Group (1985 - 2000) |
| CURRENT PUBLIC COMPANY BOARDS |
| ● | Non-executive board member of Riverstone Energy Limited (LSE: REL) |
| ● | Non-executive board member of Centennial Resource Development, Inc. (NASDAQ: CDEV) |
| OTHER POSITIONS |
| ● | Founder of Riverstone Holdings LLC and Senior Managing Director (2000-present) |
| ● | Director of boards or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates |
| David M. Leuschen | EDUCATION |
| Director since 2018 | | ● | MBA from Dartmouth’s Amos Tuck School of Business |
| Age: 68 | | ● | A.B. degree from Dartmouth College |
| Class I Director | | | |
| In 2007, Mr. Leuschen, along with Riverstone Holdings LLC 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 was selected to serve on the Board due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry. |
|
|
|
|
|
|
| | | |
| PRIOR BUSINESS EXPERIENCE |
| ● | Senior Advisor to Anadarko Petroleum Corporation (NYSE: APC) (2017-2018) |
| ● | Director, President and Chief Executive Officer of WES GP (2009 to 2017) |
| ● | Vice President and Senior Vice President of Anadarko Petroleum Corporation (2010 to 2016) |
| ● | Co-founder, President and Chief Executive Officer of Ceritas Energy, LLC (2003 to 2009) |
| ● | Energy industry consulting and management of personal business interests (1998 to 2003) |
| ● | President of Duke Energy Trading and Marketing LLC (1997 to 1998) |
| ● | Senior Vice President of Tenneco Energy, a unit of Tenneco Inc., and as President of Tenneco Energy Resources Corporation (May 1995-December 1995) |
| Donald R. Sinclair | | ● | Senior Vice President and Chief Risk Officer of Dynegy Inc. (formerly NGC Corporation) (January 1993-February 1994) |
| Director since 2018 | OTHER POSITIONS |
| Age: 62 | | ● | Chairman of the Board of Directors and President of WTX Pumping Services LLC |
| Class I Director | | ● | Director of Lucid Energy Group II, LLC |
| | ● | Director of Ascent Resources, LLC |
| EDUCATION |
| | ● | Bachelor of Business Administration degree from Texas Tech University |
| | | |
| Mr. Sinclair was selected to serve on the Board due to his significant leadership experience and his extensive investment experience in the oil and gas industry. |
On January 12, 2020, KFMDecember 20, 2018, AM Equity Holdings, LP (“AM Management”) redeemed its share of Series A Preferred Stock. As a result, each of Bayou City Energy Management, LLC (“Bayou City”) and allHPS Investment Partners, LLC (“HPS”) 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 until 2023, 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 under NASDAQ rules (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 under NASDAQ rules |
The vote of Bayou City and HPS will be the only vote required to elect such nominees to the Board (each such director, in such capacity, a “Series A Director”). So long as the Series A Preferred Stock remains outstanding, vacancies on our Board 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 immediately upon redemption of the Series A Preferred Stock.
Mr. McMullen serves as a Class III director on the Board on behalf of Bayou City, and Mr. Dimitrievich serves as a Class III director on the Board on behalf of HPS.
Riverstone VI Alta Mesa Holdings, L.P. (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 until 2023 based on its subsidiaries (collectively,and its affiliates’ beneficial ownership of Class A Common Stock as follows:
|
| | |
Holder / Beneficial Ownership and Other Requirements | | Designation Right |
| The 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 James Hackett) |
The vote of the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief underRiverstone Contributor will be the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLConly vote required to elect such nominees to the Board (each such director, in such capacity, a “Series B Director”). So long as the Series B Preferred Stock remains outstanding, vacancies on our Board 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 immediately upon redemption of the Series B Preferred Stock.
Mr. Leuschen serves as a Class I director, Mr. Lapeyre serves as a Class II director and SRII Opco (collectively,Mr. Hackett serves as a Class III director on the “SRII Debtors”Board on behalf of the Riverstone Contributor.
Board Leadership Structure
Currently, James T. Hackett serves as our Chairman of the Board. We have no policy with respect to the separation of the offices of Chairman and togetherChief Executive Officer. The Board believes that it is important to retain its flexibility to allocate the responsibilities of the offices of the Chairman and Chief Executive Officer in any way that is in the best interests of the
Company at a given point in time. Currently the offices of Chairman and Chief Executive Officer are separated with Mr. Mark P. Castiglione serving as our Chief Executive Officer.
The Board oversees the Company’s management and, with the KFM Debtors,assistance of management, is actively involved in oversight of risks that could affect the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy PetitionsCompany. During the course of each year, the Board engages in the oversight of risk in various ways, including by (i) reviewing and togetherapproving management’s operating plans and considering any risks that could affect operating results, (ii) reviewing the structure and operation of our various departments and functions, (iii) in connection with the KFM Bankruptcy Petitions,review and approval of particular transactions and initiatives, reviewing related risk analyses and mitigation plans and (iv) facilitating appropriate coordination among the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. Board committees as set forth below.
The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.
Adversary Proceeding
On September 12, 2019, an adversary proceeding was commenced byBoard has also delegated certain risk oversight responsibility to committees of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis,Board as follows: (i) the audit committee of the Board (the “Audit Committee”) oversees the Company’s guidelines and Harlan H. Chappelle (together,policies governing the “Defendants”process by which senior management assess and manage the Company’s exposure to risk, as well as the Company’s major financial risk exposures and the steps management has taken to monitor and control those exposures; (ii) the compensation committee of the Board (the “Compensation Committee”) oversees risk related to senior executive and other compensation; and (iii) the nominating and corporate governance committee of the Board (the “Nominating and Corporate Governance Committee”) oversees risk related to corporate governance. In 2019, management prepared and the Audit Committee reviewed a comprehensive enterprise risk assessment.
The Board had three standing committees during 2019: the Audit Committee, the Compensation Committee and the Nominating and Corporate Governance Committee. Each of the committees reports to the Board as it deems appropriate and as the Board may request. The composition, duties and responsibilities of these committees are set forth below.
Audit Committee
The principal functions of the Audit Committee are detailed in its Audit Committee Charter, which is available at www.altamesa.net, alleging,and include, but are not limited to:
being responsible for the appointment, compensation, retention 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 permitted non-audit services to be provided by the independent auditors or any other registered public accounting firm engaged by the Company;
reviewing the performance of the independent auditors and making decisions regarding the replacement or termination of the independent auditors;
evaluating the independence of the independent auditors by, among other things, reviewing and discussing with the independent auditors all relationships the auditors have with the Company; setting clear hiring policies for the Company for employees or former employees of the independent auditors; and monitoring compliance by the independent auditors with the auditor partner rotation requirements contained in applicable laws, rules and regulations;
reviewing and discussing with the independent auditors their annual audit plan and reviewing with management and the independent auditors’ information which is required to be reported by the independent auditor;
reviewing, among other things, the adequacy and effectiveness of the Company’s accounting and internal control policies and procedures through inquiry and discussions with the Company’s independent auditors and management;
reviewing and approving any related party transaction required to be disclosed pursuant to Item 404 of Regulation S-K promulgated by the SEC prior to us entering into such transaction; and
reviewing and discussing with management, the independent auditors and our legal advisors, as appropriate, any legal, regulatory or compliance matters as such matters may arise.
Under the NASDAQ listing standards and applicable SEC rules, the Company was required to have at least three members of the Audit Committee, all of whom must be independent. Our Audit Committee consists of Mr. Jeffrey H. Tepper and Mses. Sylvia J. Kerrigan and Diana J. Walters, with Ms. Walters serving as the Chair. We believe that (i) the crude oil, gas,Mr. Tepper and water gathering agreements between Debtor Oklahoma Energy AcquisitionsMses. Kerrigan and KFM and its subsidiaries could be rejected, (ii) certain amendmentsWalters qualify as independent directors according to the crude oilrules and gas gathering agreements were constructiveregulations of the SEC with respect to audit committee membership. We also believe that Mr. Tepper and actual fraudulent transfers, (iii) the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering related-party crude oil and gas gathering agreements, whichMs. Walters each qualify as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement“financial expert,” as such term is therefore terminated. Pursuant to the adversary proceeding complaint, AMH is seeking declaratory judgements that the gathering agreements cannot continue to burden AMH or its estates and could therefore be rejected or avoided under the Bankruptcy Code. On October 25,defined in Item 401(h) of Regulation S-K.
During 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFMAudit Committee held 13 meetings and Oklahoma Produced Water Solutions, LLC as Defendants.took action by written consent 1 time.
On December 6, 2019, the Bankruptcy Court held that the dedication provisions
Compensation Committee
The principal functions of the crude oil, gasCompensation Committee are detailed in its Compensation Committee Charter, which is available at www.altamesa.net, and water gathering agreements “ran withinclude, but are not limited to:
reviewing at least annually the land”goals and therefore could not be rejected under the Bankruptcy Code, granting summary judgment in favorobjectives of the defendants on that countCompany’s executive compensation plans;
reviewing at least annually the Company’s executive compensation plans;
evaluating annually the performance of the complaint. All other counts were reserved for trial, which commenced on December 9, 2019, but was subsequently stayed by the Bankruptcy Court at the request of the parties. The litigation remains stayed as of the date hereof.
Litigation
On January 30, 2019, the Company, James T. Hackett, our then interimCompany’s Chief Executive Officer, and determining and approving the Chief Executive Officer’s compensation level based on this evaluation;
evaluating annually the performance of the other executive officers of the Company, and determining and approving the compensation of such other executive officers;
evaluating annually the appropriate level of compensation for Board and committee service by non-employee directors;
if applicable, reviewing and discussing with management the Company’s Compensation Discussion & Analysis disclosure, and recommending to the Board that the Compensation Discussion & Analysis disclosure be included in the Company’s annual proxy statement or annual report;
if applicable, preparing the Compensation Committee Report for inclusion in the Company’s proxy statement and annual report;
reviewing at least annually the goals and objectives of the Company’s general compensation plans and other employee benefit plans, including incentive-compensation and equity-based plans;
reviewing at least annually the Company’s general compensation plans and other employee benefit plans, including incentive-compensation and equity-based plans; and
reviewing all equity-compensation plans to be submitted for stockholder approval under the NASDAQ listing standards, and reviewing and approving all equity-compensation plans that are exempt from such stockholder approval requirement.
Under the NASDAQ listing standards, the Company was historically required to have a Compensation Committee, all of whom must be independent. Until July 1, 2019, our Compensation Committee consisted of Messrs. Donald R. Sinclair and Jeffrey H. Tepper and Ms. Diana J. Walters, with Mr. Sinclair serving as the Chair. Effective July 1, 2019, Ms. Sylvia J. Kerrigan replaced Ms. Walters on the Compensation Committee. We believe that Messrs. Sinclair and Tepper and Mses. Walters and Kerrigan qualify as independent directors according to the rules and regulations of the NASDAQ with respect to compensation committee membership.
During 2019, the Compensation Committee held 8 meetings and took action by written consent 2 times.
Nominating and Corporate Governance Committee
The principal functions of the Nominating and Corporate Governance Committee are detailed in its Nominating and Corporate Governance Committee Charter, which is available at www.altamesa.net, and include, but are not limited to:
identifying individuals qualified to become members of the Board and ensuring that the Board has the requisite expertise and that its membership consists of persons with sufficiently diverse and independent backgrounds;
recommending director nominees for election to the Board at the next annual meeting of stockholders;
reviewing the Board committee structure annually and recommending directors to serve as members of each committee;
overseeing the annual self-evaluations of the Board;
making recommendations to the Board regarding governance matters;
reporting regularly to the Board regarding the activities of the Nominating and Corporate Governance Committee;
performing at least annually an evaluation of the performance of the Nominating and Corporate Governance Committee; and
reviewing and reassessing periodically the Nominating and Corporate Governance Committee Charter.
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.
Our Nominating and Corporate Governance Committee consists of Messrs. Donald R. Dimitrievich, Donald R. Sinclair, Jeffrey H. Tepper and Ms. Diana J. Walters, with Mr. Tepper serving as the Chair.
During 2019, the Nominating and Corporate Governance Committee held 1 meeting and took action by written consent 1 time.
Executive Officers
Our executive officers and their ages as of March 15, 2020, are set forth below:
|
| | | | |
| Name | | Age | | Position |
| James T. Hackett | | 66 | | Chairman of the Board |
| Mark P. Castiglione | | 49 | | Chief Executive Officer |
| John H. Campbell, Jr. | | 62 | | President and Chief Operating Officer |
| Randy L. Limbacher | | 61 | | Executive Vice President of Strategy |
| John C. Regan | | 50 | | Executive Vice President, Chief Financial Officer and Assistant Secretary |
| Kimberly O. Warnica | | 46 | | Executive Vice President, General Counsel, Chief Compliance Officer and Secretary |
James T. Hackett became our Executive Chairman of the Board certainimmediately following the closing of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination until February 2020 when he became our Chairman. He also briefly served as Chief Operating Officer— Midstream prior to the appointment of Mr. Collins and therefore, violated Section 14(a)then served as President of the Securities Exchange ActCompany’s subsidiary Kingfisher Midstream, LLC. He previously served as our Interim Chief Executive Officer as well. Mr. Hackett is a Senior Advisor at Riverstone Holdings, LLC. Prior to joining Riverstone in 2013, Mr. Hackett served as the Chairman of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that RiverstoneBoard from 2006 to 2013 and the individual defendants violated Section 20(a)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 Exchange Act. The plaintiffenergy industry. Mr. Hackett serves on the Board of Directors of Enterprise Products Holdings, LLC, Fluor Corporation (NYSE: FLR), National Oilwell Varco, Inc. (NYSE: NOV) and Talen Energy Corporation. Mr. Hackett is seeking compensatory and/or rescissory damages againsta former Chairman of the defendants. The District Court transferred this actionBoard 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 University in 1979 and 2016, respectively.
Mark P. Castiglione became our Chief Executive Officer on September 10, 2019 after serving as our Interim Executive Vice President - Strategy and Corporate Development as of June 18, 2019. He initially joined us as Chief of Staff to the U.S. District CourtPresident on January 1, 2019. He also serves as Executive Vice President of Meridian Energy LLC, a position he has held since June 2017. From January 2015 to May 2017, Mr. Castiglione managed MPC Resources, LLC (an energy advisory firm) and was engaged as Senior Advisor to SandRidge Energy, Inc. from January 2015 to June 2016. From 2010 to December 2014, he served as Senior Vice President – Business Development of Quantum Resources Management, LLC and QR Energy, LP. Prior to joining Quantum Resources, Mr. Castiglione served as Vice President – Acquisitions and Divestitures of El Paso Corporation from 2009 to 2010 and Vice President – Business Development of El Paso Exploration and Production from 2008 to 2009. Mr. Castiglione’s prior background at Encana Corporation, Burlington Resources and Simmons & Company International includes positions of increasing responsibility in corporate development, corporate finance, asset management and engineering. He began his career in 1994 as a reservoir engineer at Burlington Resources. Mr. Castiglione received a Bachelor of Science degree in petroleum engineering from Texas Tech University in 1993 and a Master of Business Administration degree from the Cox School of Business at Southern Methodist University in 1999.
John H. Campbell, Jr. became our President and Chief Operating Officer on September 10, 2019 after serving as our Interim Executive Vice President and Chief Operating Officer as of June 18, 2019. Mr. Campbell initially joined us on January 1, 2019 as Interim Chief Operating Officer - Upstream. He also serves as President and Chief Operating Officer of Meridian Energy LLC, a position he has held since June 2017. From June 2016 to June 2017, Mr. Campbell served as a partner of Quantum Energy Partners, LLC. Prior to joining Quantum Energy Partners, LLC, he served as President of QL-Energy, LLC. From 2010 to 2014, Mr. Campbell served as President and Chief Operating Officer of QR Energy, LP. From 2008 to 2015 Mr. Campbell served as President and Chief Operating Officer of Quantum Resources Management, LLC. Mr. Campbell received a Bachelor of Science degree in petroleum engineering from the University of Alabama, Tuscaloosa in 1983 and a Master of Engineering degree in petroleum engineering degree from Texas A&M University in 1987.
Randy L. Limbacher became our Executive Vice President of Strategy on September 10, 2019 after serving as our Interim President as of January 1, 2019. He also serves as the Chief Executive Officer of Meridian Energy LLC (a Houston-based energy advisory firm), a position he has held since June 2017. He currently serves on the board of directors of CARBO Ceramics Inc. and TC Energy Corporation (formerly TransCanada Corporation). From March 2017 to June 2017, Mr.
Limbacher managed his personal investments as a private investor. From April 2013 until December 2015, Mr. Limbacher served as President, Chief Executive Officer and a Director of Samson Resources Corporation, a Tulsa-based oil and gas company, which filed for Chapter 11 protection in September 2015. Mr. Limbacher served as Vice Chairman of the Southern DistrictBoard of Texas.
OnDirectors of Samson from December 2015 until the company emerged from bankruptcy in March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle, our former2017. From November 2007 until February 2013, Mr. Limbacher served as President and Chief Executive Officer and Michael A. McCabe, our former Chief Financial Officer. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b)a Director of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017,
and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.
On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.
The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.
Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.
In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”Rosetta Resources, Inc., a subsidiary of HMI), Alta Mesa, and other defendants. Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACKHouston-based oil and gas assetscompany. From February 2010 until February 2013, Mr. Limbacher also served as Chairman of the Board of Rosetta. From April 2006 until November 2007, Mr. Limbacher held the position of President, Exploration and Production - Americas for ConocoPhillips, a Houston-based energy company. Prior to that Alta Mesa distributed totime, Mr. Limbacher spent over twenty years with Burlington Resources Inc., a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACKHouston-based oil and gas assets, regardlesscompany, where he served as Executive Vice President and Chief Operating Officer from 2002 until it was acquired by ConocoPhillips in April 2006. He was a Director of when those liabilities arose. Consequently, we believe that any potential damages incurred byBurlington Resources from January 2004 until the sale of the company. Mr. Limbacher received a Bachelor of Science degree in petroleum engineering from Louisiana State University in 1980.
John C. Regan was named Executive Vice President, Chief Financial Officer and Assistant Secretary on June 18, 2019. Prior to joining us as Vice President, Chief Financial Officer and Assistant Secretary on January 7, 2019, Mr. Regan served as the Chief Financial Officer of Vine Oil and Gas LP from January 2015 to June 2018. He previously served as Chief Financial Officer of Quicksilver Resources from April 2012 through December 2014, after having served as their Chief Accounting Officer beginning in September 2007. Mr. Regan is a Certified Public Accountant with more than 25 years of combined public accounting, corporate finance and financial reporting experience.
Kimberly O. Warnica was named Executive Vice President, General Counsel, Chief Compliance Officer and Secretary on June 18, 2019. Ms. Warnica initially joined us in April 2018 as our Vice President, General Counsel, Chief Compliance Officer and Secretary. Prior to joining us, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Marathon Oil Corporation since April 2017. She previously served as Group Counsel and Assistant Secretary of Marathon Oil from October 2016 until April 2017. Prior to Marathon Oil, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Freeport-McMoRan Oil & Gas (formerly Plains Exploration and Production Company) from April 2006 until June 2016. She started her career at Andrews Kurth LLP where she practiced corporate and securities law representing a variety of clients in numerous transactional, securities and corporate governance matters. Ms. Warnica has a Bachelor’s degree from Texas A&M University and earned her J.D. from the University of Texas School of Law.
Code of Business Conduct and Ethics
We have adopted a Code of Business Conduct and Ethics applicable to our directors, officers and employees and have posted a copy at www.altamesa.net. In addition, a copy of the Code of Business Conduct and Ethics will be provided without charge upon request directed to Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company. Resources, Inc., 15021 Katy Freeway, Suite 400, Houston, Texas 77094, Attention: Secretary.
SEC Investigation
The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.
Environmental Claims
Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries 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 its oil and 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 as of December 31, 2019.
Item 4.Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities11. Executive Compensation
(a) Market InformationFor 2019, our named executive officers (“NEOs”) are:
Our Class A Common Stock and Public Warrants are currently listed on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ,” respectively. Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
Our Class C Common Stock does not trade on any market however, holders of our Class C Common Stock hold an equal number of SRII Opco Common Units that were issued upon the closing of the Business Combination. Holders of Class C Common Stock have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for an equal number of shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. Upon such an exchange, a corresponding number of shares of Class C Common Stock would be canceled.
In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Further, as part of the AMR Liquidation Plan, we expect all outstanding shares of Class A Common Stock and Class C Common Stock will be cancelled.
(b) Holders
As of January 31, 2020, there were 39 holders of record of our Class A Common Stock, 9 holders of record of our Class C Common Stock and 6 holders of record of our Public Warrants. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares of Public Warrants through nominee names.
(c) Dividends
We have not paid any cash dividends on our Class A Common Stock to date. The payment of any cash dividends on our Class A Common Stock is within the discretion of our Board of Directors (the “Board”) but, our ability to declare dividends is generally prohibited by our debt agreements and our bankruptcy filing. Holders of our Class C Common Stock are not entitled to dividends at any time.
(d) Securities Authorized for Issuance Under Equity Compensation Plans
Shares of Class A Common Stock that were issuable under our existing equity compensation plans as of December 31, 2019:
|
| | | | | | | | | |
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted-average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
Equity compensation plans approved by security holders(1) | | | | | 40,016,725 |
|
| Stock options | 3,803,287 |
| | $ | 8.79 |
| | |
PSUs(2) | 2,841,434 |
| | N/A |
| | |
| Total | 6,644,721 |
| | | | 40,016,725 |
|
_________________
|
| |
(1)Name | There were no equity compensation plans not approved by security holders. |
| Title |
(2)James T. Hackett | Assumes maximum achievement of performance targets at 200% for the 2019 and 2020 performance periods. Performance-based restricted stock units have no exercise price. In February 2020, we settled the 2019 trancheCurrent Chairman of the PSUs with an immaterial cash payment.Board and Former Executive Chairman of the Board and Interim Chief Executive Officer(1) |
| Mark P. Castiglione | Chief Executive Officer(2) |
| John H. Campbell, Jr. | President and Chief Operating Officer(2) |
| Randy L. Limbacher | Executive Vice President of Strategy(2) |
| John C. Regan | Executive Vice President, Chief Financial Officer and Assistant Secretary(3) |
(1) Mr. Hackett resigned as Interim Chief Executive Officer as of September 10, 2019 and ceased being Executive Chairman on February 19, 2020, at which time he became Chairman of the Board.
(2) Messrs. Castiglione, Campbell and Limbacher were hired to serve as officers of the Company pursuant to a letter agreement by and among Alta Mesa Services, LP, each of Messrs. Castiglione, Campbell and Limbacher and Meridian Energy LLC dated December 20, 2018, as amended and restated September 10, 2019 and as further amended and restated March 10, 2020 (the “Meridian Consulting Agreement”). Messrs. Castiglione, Campbell and Limbacher were elected to their current positions as of September 10, 2019.
(3) Mr. Regan’s employment commenced on January 7, 2019.
Executive Compensation
On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan.
(e) Performance Graph
Not required.
(f) Recent Sales Accordingly, we are no longer able to grant restricted stock or shares of Unregistered Securities
None.
(g) Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In August 2018, our Board authorized the repurchase of up to $50.0 million of the Company’s outstanding Class A Common Stock exclusivein satisfaction of any fees, commissions or other expenses related to such repurchases. Prior toour outstanding unexercised stock options, unvested restricted stock and unvested performance-based restricted stock units, and we anticipate those outstanding stock awards will be canceled as a result of our bankruptcy filing, repurchases could have been made at the Company’s discretion in accordance with applicable securities laws from time to time in open market or private transactions. All shares repurchased were retired. The authorization has no expiration date.filing.
There were no repurchases and retirements during the quarter ended December 31, 2019 and no additional repurchases are anticipated.
Item 6. Selected Financial Data
Not required.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report. 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 Buyer’s ability and willingness to close the Sale Transactions, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, 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 Annual Report, all of which are difficult to predict. As a result of these risks, uncertaintiesthe financial distress of the Company in 2019, we modified our compensation program in 2019 to consistent of base salary, a cash bonus paid at set target levels, and assumptions,longer-term incentives (“LTI”). The LTI was based on performance criteria in the forward-looking events discussed may not occur.case of the Company’s officers. Assuming achievement of a threshold level of performance, payouts under our LTI compensation program would have resulted in some compensation at levels below full target achievement, rather than an “all-or-nothing” approach.
|
| | | | | | | | | |
| Name and Principal Position | Year | Salary ($) | Bonus ($)(4) | Stock Awards ($) | Option Awards ($) | Non-Equity Incentive Plan Compensation ($)(5) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) | All Other Compensation ($) | Total ($) |
| James T. Hackett Chairman and Former Executive Chairman and Interim CEO | 2019
2018 | 462,462
442,000(3) | 247,000
0 | 0
1,405,660 | 0
2,722,288 | 859,420
0 | 0
0 | 0
0 | 1,568,882
4,569,948 |
Mark P. Castiglione Chief Executive Officer(1) | 2019
2018 | 625,000
0 | 1,325,000
0 | 0
0 | 0
0 | 700,000
0 | 0
0 | 0(6)
0 | 2,650,000
0 |
John H. Campbell, Jr. President and Chief Operating Officer(1) | 2019
2018 | 650,000
0 | 1,225,000
0 | 0
0 | 0
0 | 700,000
0 | 0
0 | 0(6)
0 | 2,575,000
0 |
Randy L. Limbacher Executive Vice President of Strategy(1) | 2019
2018 | 675,000
0 | 850,000
0 | 0
0 | 0
0 | 600,000
0 | 0
0 | 0(6)
0 | 2,125,000
0 |
John C. Regan Executive Vice President, Chief Financial Officer and Assistant Secretary(2) | 2019
2018 | 424,039
0 | 863,750
0 | 0
0 | 0
0 | 823,530
0 | 0
0 | 46,290(7)
0 | 2,157,609
0 |
(1) Messrs. Castiglione, Campbell and Limbacher commenced serving as officers on January 1, 2019 and were elected to their current positions as of September 20, 2019.
(2) Mr. Regan commenced serving as an officer on January 7, 2019.
(3) Represents salary paid in 2018 from closing of the Business Combination through December 31, 2018.
(4) For Mr. Hackett, this column represents quarterly cash bonus payments, determined by the Compensation Committee pursuant to the Company’s annual incentive compensation plan. For 2019, the amount paid was not contingent upon performance criteria. For Messrs. Castiglione, Campbell and Limbacher, this column represents regular quarterly and advanced bonus payments made pursuant to the Meridian Consulting Agreement, which amounts were not contingent upon performance criteria. For Mr. Regan, this column represents quarterly cash bonus, advanced bonus and sign-on bonus payments, none of which were contingent upon performance criteria.
(5) For Messrs. Hackett and Regan, this column represents long term incentive payments, determined by the Compensation Committee pursuant to the Company’s Long Term Incentive Plan. For Messrs. Castiglione, Campbell and Limbacher, this column represents milestone bonuses paid pursuant to the Meridian Consulting Agreement.
(6) Excludes amounts set forth in the following table as these amounts are not compensation received by the NEOs. The legal expenses reimbursed to Meridian Energy LLC were allocated between Messrs. Castiglione, Campbell and Limbacher in the same proportion as their total compensation for 2019.
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| | | | | |
| Name | Year | Meridian Energy LLC’s portion of benefits and payroll taxes | Legal Expenses Reimbursed to Meridian Energy LLC |
| Mark P. Castiglione | 2019 | 197,375 |
| 10,002 |
|
| John H. Campbell, Jr. | 2019 | 197,750 |
| 9,719 |
|
| Randy L. Limbacher | 2019 | 182,125 |
| 8,021 |
|
Overview
Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion(7) The following table describes each component of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts.All Other Compensation column for Mr. Regan:
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| | | | | | | |
| Name | Year | Relocation Cost and Expenses ($) | Company Contributions to Defined Contribution Plan ($)(a) | Total All Other Compensation ($) |
| John C. Regan | 2019 | 36,780 |
| 9,510 |
| 46,290 |
|
| |
| (a) | Reflects amounts contributed by the Company under the 401(k) employee savings and protection plan. |
Outstanding Equity Awards at 2019 AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).Year-End
On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.
The Initialfollowing table reflects outstanding stock option awards and Additional Debtors operate their businessesunvested and unearned stock awards (both time-based and performance-contingent) as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
On December 31, 2019, assuming a market value of $0.016 per share (the closing stock price of the Initial DebtorsCompany’s common stock on December 31, 2019). On February 17, 2020, Mr. Hackett waived the accelerated vesting under his letter agreement with the Company and forfeited all outstanding equity awards, including the awards listed in the table below as unexercisable and unearned.
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| | | | | | | | | |
| | Stock Awards |
| | | Option Awards | Restricted Stock/Units4 | Equity Incentive Plan Awards / Performance Units5 |
| | | Number of Securities Underlying Unexercised Options | Option Exercise Price ($) | Option Expiration Date | Number of Share or Units of Stock that Have Not Vested (#) | Market Value of Shares or Units of Stock that Have Not Vested ($) | Number of Unearned Shares, Units or Other Rights that Have Not Vested (#) | Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested ($) |
Name1 | Grant Date2 | Exercisable (#) |
Unexercisable3 (#) |
| James T. Hackett | 2/9/18 | 196,541 | 393,082 | 9.54 | 2/8/25 | | | 628,932 | 10,063 |
| |
| (1) | Messrs. Castiglione, Campbell, Limbacher and Regan were never awarded any equity. |
| |
| (2) | Award was established based on the fair market value of of a Class A share of AMR on the grant date in the table and, in the case of restricted stock and restricted stock units granted on February 9, 2018, were issued upon filing of an effective registration statement, which was April 12, 2018. |
| |
| (3) | All stock options vest in one-third increments on each anniversary of the grant date. Mr. Hackett forfeited his remaining unvested options. |
| |
| (4) | Mr. Hackett was never awarded any restricted stock. |
| |
| (5) | The number of outstanding units and estimated payout assumes target payout for each tranche of the award. In February 2020, it was determined that the tranche of 2019 performance-based units would be cashed out at 199%. However, given the Chapter 11 Bankruptcy filing of the Company, Mr. Hackett did not receive payment for the 2019 units and he forfeited his remaining unvested awards. |
Other Benefits
We provide benefits that we believe are standard in the industry to all of our employees. These benefits consist of health insurance coverage for employees and their qualified dependents and a 401(k) plan. The health and welfare benefits (net of employee contributions) were paid by the Company for all employees in 2019. We make matching contributions of 5% of eligible employee compensation to the 401(k) plan and pay all administrative costs of the plan.
In connection with the Business Combination, the Company entered into a Purchaseletter 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
of and Sale Agreement (as amended and restated in January 2020,under the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuantletter agreement, he will be entitled to whichfull accelerated vesting of all equity awards granted to him during the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash,three years after February 8, 2018 that are subject to customary purchase price adjustments (such transaction,time-based vesting and accelerated vesting of any such Company equity awards that are subject to performance-based vesting at the “AMH Sale Transaction”). Ontarget level of performance. In the event Mr. Hackett had been terminated without cause or he resigned for good reason effective as of December 31, 2019, Mr. Hackett would have received payment of $10,063 which represents the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially allin-the-money value of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).
The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A commonunvested stock and class C common stock in the Company are expected to be canceled.
The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.
In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administr
ator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.
The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.
Additional information relating to the formation of the Company and the acquisition of Alta Mesa and KFM on February 9, 2018, may be found in Item 8. Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. We have reported these distributed assets as discontinued operations for all periods presented.
Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date, including recording the fair values in the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination (“Predecessor Period”) and the period after the Business Combination (“Successor Period”). The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to February 9, 2018. The Company, including the consolidated results of Alta Mesa and Kingfisher, is the “Successor” for periods since February 9, 2018.
Accordingly, for purposes of explaining our segment results, we have presented the 2019 results with the 2018 Successor Period and the 2018 Predecessor Period results of Alta Mesa, our Upstream segment. As KFM, our Midstream segment, was acquired on February 9, 2018, our discussion of our Midstream segment results covers the 2019 results and the 2018 Successor Period results.
Outlook, Market Conditions and Commodity Prices
Our revenue and profitability depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control. Our business has been significantly affected by the price of oil due to its weighting in our production profile.
Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries;options (currently $0) and the value of the U.S. dollarunvested performance units at target level performance. On February 17, 2020, Mr. Hackett waived the accelerated vesting under the letter agreement and forfeited all outstanding equity awards.
In addition, the Company entered into an employment agreement with Mr. Regan in international currency markets. Commodity prices remainJanuary 2019. The employment agreement with Mr. Regan entitles him to an annual base salary of $450,000 and to participate in an annual performance bonus program with a target bonus award determined by the Board. For 2019, Mr. Regan’s target annual bonus amounts under this program was 95% of his annual base salary. Mr. Regan 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. Regan’s employment without cause or he resigns for good reason, within the meaning of and under the employment agreement, he will be entitled to receive (i) a prorated annual bonus for the year of termination, determined at depressed levels comparedthe discretion of the Compensation Committee and 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 past years, whichtime-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) a lump-sum payment equal to $24,000 for outplacement services, (iv) 18 months of his annual base salary and 1.5 times the greater of his target annual bonus and the annual bonus paid to him for the prior year and (v) payment for up to 18 months of 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 6 months. Mr. Regan is also entitled to receive the amounts under clauses (i), (iii), (iv) and (v) of the preceding sentence if his employment terminates due to death or disability, under and within the meaning of their respective employment agreement. If Mr. Regan’s qualifying termination of employment occurs during the fifteen months following a change in control (within the meaning of Mr. Regan’s 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 additional 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. Regan’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. Mr. Regan 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.
Mr. Regan’s employment agreement further entitles him, if a termination of employment occurs before January 7, 2021, to payment for any excise taxes imposed under Section 4999 of the Internal Revenue Code as a result of a change in control, plus an additional amount that puts him in the same after-tax position he would have hadbeen absent the imposition of excise taxes under Section 4999 of the Internal Revenue Code.
Mr. Regan’s employment agreement provides him with post-termination benefits in a negative impactvariety of circumstances. The amount of compensation payable in some cases may vary depending on the valuenature of our oil and gas properties and our midstream assets, and the future outlook for prices continues to be unpredictable.
Ability to Continuetermination, whether as a Going Concernresult of voluntary termination, involuntary not-for-cause termination, termination following a change of control and in the event of disability or death of the executive. The following are general definitions that apply to the termination scenarios described above. These definitions have been summarized and are qualified in their entirety by the full text of the applicable plans or agreements to which Mr. Regan is a party.
AMR’sAnticipatory Termination generally means a termination of the employment within the three (3) month period ending immediately prior to the Change in Control date (in which the Change in Control is a “change in control event” within the meaning of Code Section 409A), but only significant assetif (a) Mr. Regan’s employment with the Company was (i) terminated by the Company without Cause or (ii) terminated by Mr. Regan for Good Reason, and (b) it is its ownershipreasonably demonstrated by Mr. Regan that such termination of employment (1) was at the request of a partnership interestthird party who has taken steps reasonably calculated to effect such Change in SRII Opco. AsControl or (2) otherwise arose in connection with or anticipation of such weChange in Control.
Cause is generally defined as: (A) Mr. Regan’s final conviction by a court of competent jurisdiction of a felony involving moral turpitude, or entering the plea of nolo contendere to such felony by Mr. Regan; (B) the commission by Mr. Regan of a demonstrable act of material fraud, or a proven and material misappropriation of funds or other property, of or upon the
Company or any affiliate; (C) the engagement by Mr. Regan, without the written approval of the Company, 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; or (D) the breach by Mr. Regan of any material provision of his employment agreement. With respect to items (C) and (D) above, in order to constitute “Cause” hereunder, Mr. Regan must also fail to cure such breach within a reasonable time period set by the Company but in no event less than twenty (20) calendar days after his receipt of such notice.
Change of Control means and includes each of the following:
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| (A) | A transaction or series of transactions (other than an offering of common stock to the general public through a registration statement filed with the Securities and Exchange Commission or a transaction or series of transactions that meets the requirements of clauses (1) and (2) of subsection (C) below) whereby any “person” or related “group” of “persons” (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act) (other than the Company, any of its subsidiaries, an employee benefit plan maintained by the Company or any of its subsidiaries or a “person” that, prior to such transaction, directly or indirectly controls, is controlled by, or is under common control with, the Company) directly or indirectly acquires beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act) of securities of the Company possessing more than 50% of the total combined voting power of the Company’s securities outstanding immediately after such acquisition; or |
(B) During any period of two consecutive years, individuals who, at the beginning of such period, constitute the Board together with any new Director(s) (other than a Director designated by a person who shall have no meaningful cash availableentered into an agreement with the Company to meet our obligations apart from cash heldeffect a transaction described in subsections (A) or (C)) whose election by our subsidiaries. Asthe Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds of the Directors then still in office who either were Directors at the beginning of such two-year period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority thereof; or
(C) The consummation by the Company (whether directly involving the Company or indirectly involving the Company through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of the Company’s assets in any single transaction or series of related transactions, or (z) the acquisition of assets or stock of another entity, in each case other than a transaction:
(1) which results in the Company’s voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into voting securities of the Company or the person that, as a result of the bankruptcy filings by us andtransaction, controls, directly or indirectly, the Company or owns, directly or indirectly, all or substantially all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligationsthe Company’s assets or otherwise succeeds to the extent authorized by the Bankruptcy Code or by orderbusiness of the Bankruptcy Court. The bankruptcy filings byCompany (the Company or such person, the Initial Debtors“Successor Entity”)) directly or indirectly, at least a majority of the combined voting power of the Successor Entity’s outstanding voting securities immediately after the transaction; and
(2) after which no person or group beneficially owns voting securities representing 50% or more of the Additional Debtors (collectively, “the Debtors”) triggered defaults incombined voting power of the Alta Mesa RBL,Successor Entity; provided, however, that no person or group shall be treated for purposes of this clause (2) as beneficially owning 50% or more of the 2024 Notes andcombined voting power of the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actionsSuccessor Entity solely as a result of the voting power held in the Company prior to the consummation of the transaction.
Notwithstanding the foregoing, in no event shall the following constitute a Change in Control: (i) the Business Combination or any transactions occurring in connection therewith, or (ii) any initial public offering of any subsidiary of the Company that owns all or part of the Company’s Midstream Assets or any other sale or disposition of such defaults. Midstream Assets directly or indirectly by the Company in connection with such initial public offering.
The DebtorsBoard as in effect immediately prior to the occurrence of a Change in Control shall have full and final authority, which shall be exercised in its discretion, to determine conclusively whether a Change in Control has occurred pursuant to the above definition, the date of the occurrence of such Change in Control and any incidental matters relating thereto; provided that any exercise of such authority in conjunction with a determination regarding whether a Change in Control is a “change in control event” (as defined in Treasury Regulation Section 1.409A-3(i)(5)) shall be determined on a basis consistent with such regulation.
Good Reason means the occurrence of any of the following without Mr. Regan’s prior written consent, if not cured and corrected by the Company within 60 days after written notice thereof is provided by Mr. Regan to the Company, provided such notice is delivered within 90 days after the occurrence of the applicable condition or event and that Mr. Regan resigns from employment with the Company within 90 days following expiration of such 60-day cure period: (a) the demotion or reduction in title or rank of Mr. Regan with the Company, or the assignment to Mr. Regan of duties that are also subjectmaterially inconsistent with his positions, duties and responsibilities with the Company, or any removal of Mr. Regan from, or any failure to limitations imposednominate for
re-election Mr. Regan to, any of such positions (other than a change due to his Disability or as an accommodation under Bankruptcy Court approved cash collateral orders requiring usthe American with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with Mr. Regan’s termination of employment for Cause, Disability or death; (b) the reduction of Mr. Regan’s annual base salary and/or target bonus opportunity, as compared to (i) adherehis aggregate base salary and target bonus opportunity as effective immediately prior to such reduction, if such reduction of base salary and/or target bonus opportunity, on an approved budget withaggregated basis, is five percent (5%) or greater of the aggregate base salary and target bonus opportunity as effective immediately prior to such reduction; or (c) a relocation of Mr. Regan’s principal work location to a location in excess of 50 miles from its then current location.
Disability generally means that (a) Mr. Regan is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or last for a continuous period of not less than 12 months, or (b) by reason of any medically determinable physical or mental impairment which can be expected to result in death or to last for a continuous period of not less than 12 months, Mr. Regan is receiving income replacement for a period of not less than three months under an agreed-upon varianceaccident and (ii) meet certain milestones.health plan covering employees of the Company.
We expect to sellGiven the anticipated sale of substantially all of ourthe Company’s assets no later than mid-April 2020. Following the expected sale,and subsequent liquidation, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business duringuse the first half of 2020,right in bankruptcy to reject Mr. Regan’s employment agreement, which will result in an unsecured pre-petition claim against the dissolutionestate of the Company for amounts due but not paid. In addition, upon closing of the sale of the Company’s assets, we expect to waive the non-compete provisions of Mr. Regan’s employment agreement.
2019 Director Compensation
In 2018, the Company adopted a director compensation program under which each director who is not an employee and is not affiliated with the Riverstone Contributor, Bayou City, HPS or 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.
Effective April 1, 2019, the disinterested members of the Board approved an increase in the annual director fee to $237,500 and a reduction in the stock awards under the LTIP to $0, which represents a $12,500 decrease from the prior compensation package. In addition, the disinterested members of the Board approved a cash payment of $2,000 for each Board meeting attended per calendar year in excess of seven meetings and special meeting fees of $2,000 per day to address time commitments outside of Board meetings should those be warranted. There is a cap of $25,000 per month on additional and special meeting fees.
Annual director fees under the program are payable in arrears in four equal quarterly installments, provided that the amount of each payment in respect of annual fees will be prorated for any portion of a quarter that a director is not serving on our Board or on a particular committee. Director meeting fees are payable monthly in arrears.
2019 Director Compensation Table
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| | | | |
| Name | Fees Earned or Paid in Cash ($)1 | Stock Awards ($) | All Other Compensation ($) | Total ($) |
| Diana J. Walters | 284,702 | 0 | 0 | 284,702 |
| Donald R. Sinclair | 263,702 | 0 | 0 | 263,702 |
| Jeffrey Tepper | 280,202 | 0 | 0 | 280,202 |
| Sylvia J. Kerrigan | 239,750 | 0 | 0 | 239,750 |
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| (1) | Represents fees earned with respect to the annual Board retainer, applicable committee retainers and any meeting fees. The retainer amounts are earned quarterly and prorated for actual time served. The meeting fees are earned monthly. |
No change in the director compensation program is expected for 2020.
Our securities trading policy provides that executive officers, including the NEOs and directors, may not 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 executive officers and directors may only be made during certain windows of time and under the other conditions contained in our policy.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth information known to the Company regarding ownership of its shares of voting securities of the Company, which consists of Class A Common Stock and Class C Common Stock, as of February 29, 2020 except as noted:
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 directors and each NEO; 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 382,986,039 shares of Class A Common Stock and Class C Common Stock issued and outstanding in the aggregate as of February 29, 2020. 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.
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| | | | | | | | | |
Name and Address of Beneficial Owners(1) | | Number of Shares of Voting Securities | Stock Acquirable Within 60 days(2) | Total Beneficial Ownership | Percent of Class % |
| 5% or Greater Stockholders | | | | | |
| Investment vehicles affiliated with Riverstone VI Alta Mesa Holdings, L.P. (3) | | 85,776,000 |
| 28,466,666 |
| 114,242,666 |
| 29.8 | % |
| Orbis Investment Management Limited(4) | | 24,717,139 |
| — |
| 24,717,139 |
| 6.5 | % |
| High Mesa Holdings, LP(5)(8) | | 134,155,838 |
| — |
| 134,155,838 |
| 35.0 | % |
| HPS Investment Partners, LLC(5)(6)(8) | | 80,014,799 |
| — |
| 80,014,799 |
| 20.9 | % |
| Bayou City Energy Management LLC (5)(7)(8) | | 85,439,251 |
| | 85,439,251 |
| 22.3 | % |
| Directors and Executive Officers | | | | | |
| James T. Hackett | | — |
| 196,541 |
| 196,541 |
| * |
| David M. Leuschen(3) | | — |
| — |
| — |
| — |
|
| Pierre F. Lapeyre, Jr.(3) | | — |
| — |
| — |
| — |
|
| William W. McMullen | | — |
| — |
| — |
| — |
|
| Don Dimitrievich | | — |
| — |
| — |
| — |
|
| Sylvia J. Kerrigan | | 24,823 |
| — |
| 24,823 |
| * |
| Jeffrey H. Tepper | | 51,344 |
| — |
| 51,344 |
| * |
| Diana J. Walters | | 51,344 |
| | 51,344 |
| * |
| Donald R. Sinclair | | 18,344 |
| — |
| 18,344 |
| * |
| Mark P. Castiglione | | — |
| — |
| — |
| — |
|
| John H. Campbell, Jr. | | — |
| — |
| — |
| — |
|
| Randy L. Limbacher | | — |
| — |
| — |
| — |
|
| John C. Regan | | — |
| — |
| — |
| — |
|
| All directors and executive officers, as a group (14 individuals) | | 167,437 |
| 260,735 |
| 428,172 |
| * |
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| (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) | Represents options exercisable within 60 days. The options are currently out of the money with a strike price between $7.01 and $9.54. In the case of investment vehicles affiliated with Riverstone VI Alta Mesa Holdings, L.P., represents warrant exercisable within 60 days at a strike price of $11.50, as may be adjusted pursuant to that certain Warrant Agreement dated as of March 23, 2017 between the Company and Continental Stock Transfer & Trust Company. |
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| (3) | Includes 16,548,894 shares of Class A Common Stock and warrants to purchase 15,133,333 shares of Class A Common Stock held of record by Silver Run Sponsor II, LLC, 18,522,000 shares of Class A Common Stock and warrants to purchase 7,916,012 shares of Class A Common Stock held of record by Riverstone VI SR II Holdings, L.P. (“Fund VI Holdings”), 25,857,148 shares of Class A Common Stock and warrants to purchase 4,561,992 shares of Class A Common Stock held by Riverstone AMR Partners, L.P. (“AMR Partners”), 1,720,243 shares of Class A Common Stock and warrants to purchase 303,504 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 and warrants to purchase 551,825 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 and an equal number of Common Units, each of which may be exchanged on a one-for-one basis for shares of Class A Common Stock, held of record by Riverstone VI Alta Mesa Holdings, L.P. and, together with Silver Run Sponsor II, LLC, Fund VI 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, 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 Riverstone VI Alta Mesa Holdings, L.P. and Fund VI Holdings, which is the sole and managing member of Silver Run Sponsor II, LLC. 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 its subsidiaries.
These factors, including historic recurring operating losses, raise substantial doubt about our abilityRobert M. Tichio. As such, each of Riverstone Energy GP, Riverstone Energy GP VI Corp, Riverstone Holdings, LLC, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to continue as a going concern.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.
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| (4) | Based on information contained in Schedule 13G/A filed on October 10, 2019 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. |
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| (5) | The sole general partner of the High Mesa Holdings LP (“High Mesa”) is High Mesa Holdings GP, LLC (“High Mesa GP”). High Mesa, Inc. (“HMI”) holds a majority of the outstanding limited partner interests in High Mesa and all of the outstanding limited liability company interests in High Mesa GP. The interests of High Mesa are beneficially owned (either directly or through interests in HMI) by three groups, each consisting of affiliated parties: (i) AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Riverstone Holdings, LLC, LP, Petro Operating Company Holdings, Inc., Harlan H. Chappelle, Gene Cole, Mike McCabe, Dale Hayes, AM Management and MME Mission Hope, LLC (collectively, the “Management Holders”), (ii) HPS, 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, BCE-MESA Holdings, LLC, and BCE-AMH Holdings, LLC (collectively, the “Bayou City Holders”). The Class C Common Stock owned by High Mesa is subject to a voting agreement pursuant to which High Mesa 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 High Mesa of each such group. Mr. Ellis (who is our former Chief Operating Officer - Upstream and one of our former 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 Management, 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 High Mesa and the other High Mesa holders except to the extent of their respective pecuniary interests therein. |
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| (6) | Based on information contained in Schedule 13D filed on March 21, 2018, as amended on June 9, 2018, by HPS. The principal address of HPS is 40 West 57th Street, 33rd Floor, New York, New York 10019. HPS manages, directly or indirectly, each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, a wholly-owned subsidiary of Offshore Mezzanine Partners Master Fund II, L.P., KFM Institutional, LLC, a wholly-owned subsidiary of Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., and Jade Real Assets Fund, L.P. (collectively, the “HPS Kingfisher Members”), and HPS, 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., United Insurance Company of America, and Jade Real Assets Fund, L.P. (collectively, the “HPS Alta Mesa Holders”). Therefore, HPS may be deemed to be the beneficial owner of all shares of the Issuer’s Class A Common Stock beneficially owned by each of the HPS Kingfisher Members and the HPS Alta Mesa Holders. Included in the HPS Alta Mesa Holders’ beneficial ownership, HPS manages, directly or indirectly, the HPS Alta Mesa Holders that indirectly own, through HMI, a certain percentage of ARM-M I, LLC, a member of the Kingfisher Contributor (“ARM-MI”), and HMS Kingfisher HoldCo, LLC, a member of the Kingfisher Contributor (“HMS Kingfisher”); therefore, HPS may be deemed to be the beneficial owner of such proportionate percentage of shares of the Issuer’s Class A Common Stock beneficially owned by HMI through HMI’s direct ownership of HMS Kingfisher and partial indirect ownership of ARM-MI. |
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| (7) | Based on information contained in Schedule 13D/A filed on August 22, 2018 and Form 4s filed on August 31, 2018 and September 7, 2018 by Bayou City. The principal address of Bayou City is 1201 Louisiana Street, Suite 3308, Houston, Texas 77002. Bayou City manages, directly or indirectly, each of BCE-AMH Holdings, LLC and BCE-MESA Holdings, LLC (the “BCE Alta Mesa Holders”) and BCE-AMR Holdings LLC (together with the BCE Alta Mesa Holders, the “BCE Holders”). Therefore, Bayou City may be deemed to be the beneficial owner of all shares of the Issuer’s Class A Common Stock beneficially owned by each of the BCE Holders. The BCE Alta Mesa Holders indirectly own, through HMI, a certain percentage of ARM-MI, a member of KFM Holdco, LLC, and HMS Kingfisher, a member of KFM Holdco, LLC; |
Delisting from Stock Exchange
therefore, Bayou City may also be deemed to be the beneficial owner of such proportionate percentage of shares of the Issuer’s Class A Common Stock beneficially owned by HMI through HMI’s direct ownership of HMS Kingfisher and partial indirect ownership of ARM-MI.
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| (8) | All or a portion of this figure reflects shares of Class C Common Stock. |
Securities Authorized for Issuance Under Equity Compensation Plans
Information required by this section was provided in Part II, Item 5 of the Company’s Form 10-K filed on March 5, 2020.
As
Private Placement Warrants
In March 2017, Silver Run Sponsor II, LLC purchased from us 15,133,333 private placement warrants (“Private Placement Warrants”) at a resultprice of $1.50 per whole warrant in a private placement that occurred simultaneously with the closing of our failure to complyinitial public offering. Each Private Placement Warrant is exercisable for one share of Class A Common Stock at a price of $11.50 per share. The Private Placement Warrants are non-redeemable and exercisable on a cashless basis so long as they are held by our Silver Run Sponsor II, LLC or its permitted transferees.
In February 2020, we filed a Form 15 with the continued listing requirementsSEC to deregister our warrants under Section 12(g) of the NASDAQ, trading inSecurities Exchange Act of 1934, as amended, and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
Forward Purchase Agreement
In March 2017, we entered into 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 up to 13,333,333 warrants (“Forward Purchase Warrants”), for up to $400,000,000 or $10.00 per unit. Each Forward Purchase Warrant has the same terms and provisions as each Private Placement Warrant.
In February 2018, the Fund VI Holdings purchased 40,000,000 shares of our Class A Common Stock and public warrants was suspended in September 2019, and they are now traded over13,333,333 Forward Purchase Warrants pursuant to the counter under the trading symbols “AMRQQ” and “AMRWQ”, respectively. Forward Purchase Agreement for an aggregate purchase price of $400 million.
In February 2020, we filed formsa Form 15 with the Securities and Exchange CommissionSEC to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
DerivativesIndemnity Agreements
In February 2018, we entered into indemnity agreements with Messrs. Leuschen, Lapeyre, Jr., McMullen, Dimitrievich and 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 officers and/or directors following the Business Combination. In addition, we amended the indemnity agreements previously entered into with Messrs. Hackett and Tepper, Mr. William D. Gutermuth and Ms. Walters to make certain changes to reflect the Business Combination. We previously operated a hedging programalso entered into indemnity agreements with Messrs. Collins, Castiglione, Campbell, Limbacher, Regan and Emerson and Ms. Warnica in accordanceconnection with requirements undertheir appointment as officers of the Alta Mesa RBL. SettlementsCompany. Each indemnity agreement provides that, subject to limited exceptions, we will indemnify the director or officer to the fullest extent permitted by law for claims arising in his or her capacity as director or officer.
Amended and fair value changes in our derivatives had significant impacts on our resultsRestated Limited Partnership Agreement of operations. Our derivatives were reported at fair value and were sensitive to changes in the price of oil and gas. Changes in derivatives were reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period.
In connection with the closing of the Business Combination, we and High Mesa, KFM Holdco, LLC (the “Kingfisher Contributor”) and Riverstone VI Alta Mesa’s bankruptcyMesa Holdings, L.P. (the “Riverstone Contributor” and, together with the Kingfisher Contributor, the “Contributors”) entered into an amended and restated limited partnership agreement (the “SRII Opco LPA”) of SRII Opco, LP (“SRII Opco”). The operations of SRII Opco and the rights and obligations of the holders of SRII Opco common units, are set forth in the SRII Opco LPA.
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 controls all day-to-day business affairs and decision-making of SRII Opco without the approval of any other partner, unless otherwise stated in the SRII Opco LPA. As such, the General Partner, through its officers and directors, is responsible for all operational and administrative decisions of SRII Opco and the day-to-day management of SRII Opco’s business.
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 reasonable out-of-pocket expenses incurred on behalf of SRII Opco, including all 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 SRII Opco LPA 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 SRII Opco LPA). We expect SRII Opco may make distributions out of distributable cash periodically to the extent permitted by the debt agreements of SRII Opco’s subsidiaries and necessary to enable us to cover our operating expenses and other obligations. In addition, the SRII Opco LPA 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 income taxes.
SRII Opco common unit Redemption Right. The SRII Opco LPA provides a redemption right to the Contributors which entitles them 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 a one-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 delivery of a notice of redemption (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). In the event of a “reclassification event” (as defined in the SRII Opco LPA), 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 for cancellation. The SRII Opco LPA requires that we cancelled (priorcontribute cash or shares of our Class A Common Stock to contract settlement date)SRII Opco in exchange for a number of SRII Opco common units equal to the number of SRII Opco common units to be redeemed. SRII Opco will then distribute such cash or shares of our Class A Common Stock to such Contributor to complete the redemption. At our option, we may effect a direct exchange of cash or our Class A Common Stock for such SRII Opco common units in lieu of such a redemption. Any Class C common stock exchanged or canceled for SRII Opco common units will be canceled.
Change of Control. If a “general partner change of control” (as defined below) occurs, we have the right to require each partner of SRII Opco (other than us) to cause SRII Opco to redeem some or all open derivative contractsof such partner’s SRII Opco common units and a corresponding number of shares of Class C Common Stock, in September 2019each case, held prior to 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 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 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 of One-to-One Ratios. The SRII Opco LPA includes provisions intended to ensure that we maintain a one-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 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 their economic interest in SRII Opco.
Transfer Restrictions. The SRII Opco LPA 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.
Indemnification and Exculpation. The SRII Opco LPA provides for netindemnification 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.
See Exhibit 3.5 to our Form 10-K for a copy of the SRII Opco LPA.
Registration Rights Agreements
In March 2017, we entered into a registration rights agreement (the “Sponsor Registration Rights Agreement”) with Silver Run Sponsor II, LLC 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 Silver Run Sponsor II, LLC and such former and current directors upon the conversion of their founder shares at the closing of the Business Combination 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 Business Combination, 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 were 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 were required to, within 30 calendar days after consummation of certain transactions in connection with the Business Combination (the “Transactions”), file the registration statement registering the resale of the securities issued to Fund VI Holdings thereunder.
The holders of a majority of the Registrable Securities 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 were required to, within 30 calendar days after consummation of the Transactions, file the registration statement registering the resale of the Contributor Shares. Additionally, under the Business Combination Registration Rights Agreement, High Mesa is entitled to demand six underwritten offerings, the Riverstone Contributor is entitled to demand three underwritten offerings and the Kingfisher Contributor is entitled to demand two underwritten offerings, in each case if the offering is reasonably expected to result in gross proceeds of more than $50 million.
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 applicable lock-up period, which has occurred.
There are not currently any effective registration statements.
Series A Certificate of Designation
Upon the closing of the Business Combination, we filed with the Delaware Secretary of State 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 of the Business Combination. In connection with the resignations of Messrs. Chappelle and Ellis, AM Management and the Company entered into a letter agreement pursuant to which AM Management agreed to redeem its share of Series A-3 Preferred Stock.
Bayou City and HPS 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 by us upon the earlier to occur of (1) the fifth anniversary of the closing date, (2) the holder’s optional redemption of such Series A Preferred Stock or (3) upon a breach of the transfer restrictions described above.
See Item 10 for details on the Board Appointments of our Series A Preferred Stock holders.
The vote of Bayou City and HPS will be the only vote required to elect such nominees to the Board (each such director, in such capacity, a “Series A Director”). So long as the Series A Preferred Stock remains outstanding, vacancies on our Board 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 immediately upon redemption of the Series A Preferred Stock as described above.
Series B Certificate of Designation
Upon the closing of the Business Combination, we filed with the Delaware Secretary of State 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 of the Business Combination, (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.
See Item 10 for details on the Board Appointments of our Series B Preferred Stock holder.
Management Services Agreement
In connection with the closing of the Business Combination, we entered into a management services agreement (the “HMI Agreement”) with HMI. Under the HMI Agreement, during the 180-day period following the closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”), in each case, subject to and in accordance with an approved budget. Thereafter, the HMI Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.
Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa Holdings, LP (“Alta Mesa”) to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (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 reimbursable pursuant to the HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $4.0 million. Proceeds$9.8 million and $10.1 million, respectively, for costs and expenses incurred on HMI’s behalf. In 2019, we billed HMI $0.8 million for incremental costs incurred and have received were usedapproximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. While we are pursuing remedies under applicable law in connection with repayment of this receivable, we have fully reserved for all amounts due from HMI because we believe there is substantial doubt about HMI’s ability to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. After September 2019, we held no open derivative positions.
For 2019, we recognized a net loss on our derivatives of $11.7 million,payment, which includes $7.6 million in cash settlements received for derivatives.
Impairments
2019
As noted above, the Initial Debtors filed for bankruptcy protection in September 2019 and the Additional Debtors filedis further complicated by HMI’s filing for bankruptcy protection in January 2020.
Tax Receivable Agreement
We are party to a Tax Receivable Agreement (“TRA”) with SRII Opco, High Mesa, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of any realized net cash savings, in U.S. federal, state and local income tax 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 AMR 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 KFM or otherwise used in KFM’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 TRA. Also, under the TRA, we retain the benefit of the remaining 15% of these cash savings. As a result of our bankruptcy filings and previous restrictions by our lenders on our ability to access additional capital, our ability to incur the levels of spending necessary to continue to develop our upstream properties and expand our midstream operations were significantly restricted. This negatively impacted our future drilling plans and our expectations regarding production levels, which contributed to lower throughput expectations for our midstream processing assets. In addition, the Sale Transactions reflect prices of $232.0 million for substantially all of the upstream properties and assets and $88.0 million for our midstream assets. As these prices were below the carrying value of the respective assets, we adjusted our carrying values down to the expected sales prices, after estimated direct sales costs, as we believe the Buyer has the intent and ability to close the Sale Transactions.
Additionally, as a result of the expected sales of our assets described above and our expectations of contracts that will be rejected in bankruptcy, we also recognized impairments of our operating lease right-of-use assets and a long-term prepaid asset due to our inability to recover the carrying value of these assets.
2018
In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place based on our 2018 drilling results.
In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party.
As the late-2018 outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and elected to abandon the project. We conducted an impairment analysis resulting in the recognition of an impairment charge of $16.0 million during the 2018 Successor Period to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018.
Based on an estimation of the fair value of KFM utilizing an income approach that took into consideration the late 2018-outlook for Alta Mesa and third-party volumes available for processing, we determined that a portion of the value of KFM’s plant and equipment and all of KFM’s intangible assets and goodwill were impaired at December 31, 2018.
The summary of impairment expense follows (there was no impairment expense during the 2018 Predecessor Period):
|
| | | | | | | |
| (in millions) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Impairment attributable to: | | | |
| Upstream | | | |
| Unproved properties | $ | 31.0 |
| | $ | 742.1 |
|
| Proved properties | 484.8 |
| | 1,291.6 |
|
| Operating lease right-of-use assets | 13.3 |
| | — |
|
| Other long-term assets | 27.3 |
| | �� |
|
| Total Upstream | 556.4 |
| | 2,033.7 |
|
| Midstream | | | |
| Investment in Cimarron | — |
| | 16.0 |
|
| Property and equipment | 348.6 |
| | 68.4 |
|
| Operating lease right-of-use assets | 0.3 |
| | — |
|
| Intangible assets | — |
| | 395.0 |
|
| Goodwill | — |
| | 692.0 |
|
| Total Midstream | 348.9 |
| | 1,171.4 |
|
| | | | |
| Total impairment of assets | $ | 905.3 |
| | $ | 3,205.1 |
|
Results of Operations
Business Segments
Our discussion of results of operations is presented on a segment basis. Our two reportable segments are (1) Upstream and (2) Midstream, which separately feature distinct revenue producing activities. We evaluate Upstream and Midstream segment performance using Adjusted EBITDAX and Adjusted EBITDA, respectively.
The Company’s management believes Adjusted EBITDAX and Adjusted EBITDA are useful because they allow users 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 or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should not be considered as an alternative to our segments’ net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports. The Company’s applicable corporate activities have also been allocated to the supported business segments.
For the year ended December 31, 2019 compared to the periods from February 9, 2018 through December 31, 2018 (2018 Successor Period) and January 1, 2018 through February 8, 2018 (Predecessor Period)
The tables included below set forth financial information for the year ended December 31, 2019. The 2018 Successor Period and the Predecessor Period are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined 2018 Successor Period from February 9, 2018 through December 31, 2018 and the Predecessor Period from January 1, 2018 through February 8, 2018 as the “2018 Period”.
Upstream Segment Results of Operations
Our Upstream segment was impacted by the Business Combination, which caused our 2018 results to be separately presented between Successor and Predecessor Periods. In preparing the following discussion, we have provided a combined total to arrive at a full year 2018 amount and context for the change of such full year amount to the 2019 comparable amount. We view 2018 as a single reporting period since the impact of the Business Combination was limited to the items described below. We believe that this approach:
allows readers of our financial statements to see how management has evaluated the operating results; and
provides readers of our financial statements with adequate context for their analysis of our operating results.
The impact to our Upstream results following the Business Combination primarily relates to increased depletion expense associated with a step-up for proved oil and gas properties and to impairment expense which is associated with the step-up for both unproved and proved oil and gas properties. We do not believe that the presentation of full pro forma segment results is more preferable than the information that follows.
Revenue
Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our revenue and production data for the periods presented:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands, except per unit data) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Net production: | | | | | | |
| Oil (Mbbl) | 5,885 |
| | 5,053 |
| | | 494 |
|
| Natural gas (MMcf) | 24,802 |
| | 16,913 |
| | | 1,609 |
|
| NGLs (Mbbl) | 2,760 |
| | 2,268 |
| | | 151 |
|
| Total (MBoe) | 12,779 |
| | 10,140 |
| | | 914 |
|
| | | | | | | |
| Average net daily production volume: | | | | | | |
| Oil (Mbbld) | 16.1 |
| | 15.4 |
| | | 12.7 |
|
| Natural gas (MMcfd) | 67.9 |
| | 51.9 |
| | | 41.2 |
|
| NGLs (Mbbld) | 7.6 |
| | 7.0 |
| | | 3.9 |
|
| Total (MBoed) | 35.0 |
| | 31.1 |
| | | 23.4 |
|
| | | | | | | |
| Average sales prices before hedging: | | | | | | |
| Oil (per bbl) | $ | 55.79 |
| | $ | 63.99 |
| | | $ | 62.68 |
|
| Natural gas (per Mcf) | $ | 2.16 |
| | $ | 2.57 |
| | | $ | 2.66 |
|
| NGLs (per bbl) | $ | 14.50 |
| | $ | 18.98 |
| | | $ | 26.41 |
|
| | | | | | | |
| Revenue | | | | | | |
| Oil sales | $ | 328,386 |
| | $ | 323,299 |
| | | $ | 30,972 |
|
| Natural gas sales | 53,693 |
| | 43,407 |
| | | 4,276 |
|
| NGL sales | 40,026 |
| | 43,039 |
| | | 4,000 |
|
| Total Upstream sales revenue | $ | 422,105 |
| | $ | 409,745 |
| | | $ | 39,248 |
|
| | | | | | | |
| Gain on sale of assets | $ | 1,488 |
| | $ | 4,751 |
| | | $ | 840 |
|
Oil revenue for 2019 decreased compared to the 2018 Period due to a decrease in average market prices in 2019, which was partially offset by an increase in production. The increase in production in 2019 was due to an increase in the number of wells drilled and new wells on production as a consequence of the significant 2018 capital expenditure program.
NGL revenue for 2019 decreased compared to the 2018 Period due to a decrease in average market prices in 2019, which was partially offset by an increase in production. The pricing reduction primarily relates to our election of the treatment of ethane volumes in our contract with KFM. Under our gathering contract with KFM, we have an ability to determine ethane recovery volumes as either a fixed recovery or at the actual levels that the plant can recover. In 2019, we elected to recover ethane volumes at a fixed rate until August, which had the impact of increasing the NGLs volume but decreasing the price received per barrel as the total sales value remained unchanged. Beginning in August 2019, we elected to recover actual ethane volumes. The increase in production volume was primarily due to our 2018 development activities.
Gain on sale of assets primarily includes gains from the sale of seismic data in 2019 and the 2018 Period.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Gain (loss) on derivatives: | | | | | | |
| Realized gains (losses) - | | | | | | |
| Oil | $ | 6,858 |
| | $ | (36,505 | ) | | | $ | (3,819 | ) |
| Natural gas | 784 |
| | (2,456 | ) | | | 1,523 |
|
| Total realized gains (losses) | 7,642 |
| | (38,961 | ) | | | (2,296 | ) |
| Unrealized gains (losses) | (19,386 | ) | | 28,714 |
| | | 8,959 |
|
| Total gain (loss) on derivatives | $ | (11,744 | ) | | $ | (10,247 | ) | | | $ | 6,663 |
|
Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each twelve month period.
In connection with Alta Mesa’s bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts in September 2019 for net proceeds of approximately $4.0 million.
Operating Expenses
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands, except per unit data) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Operating expenses: | | | | | | |
| Lease operating | $ | 79,884 |
| | $ | 60,547 |
| | | $ | 4,408 |
|
| Transportation and marketing | 70,324 |
| | 50,038 |
| | | 3,725 |
|
| Production taxes | 19,455 |
| | 16,865 |
| | | 953 |
|
| Workovers | 2,652 |
| | 5,563 |
| | | 423 |
|
| Exploration | 52,354 |
| | 34,085 |
| | | 7,003 |
|
| Depreciation, depletion and amortization | 120,617 |
| | 133,554 |
| | | 11,670 |
|
| Impairment of assets | 556,427 |
| | 2,033,712 |
| | | — |
|
| General and administrative | 59,897 |
| | 114,735 |
| | | 21,234 |
|
| Total Upstream operating expense | $ | 961,610 |
| | $ | 2,449,099 |
| | | $ | 49,416 |
|
| | | | | | | |
| Select operating expenses per BOE: | | | | | | |
| Lease operating | $ | 6.25 |
| | $ | 5.97 |
| | | $ | 4.82 |
|
| Transportation and marketing | 5.50 |
| | 4.93 |
| | | 4.08 |
|
| Production taxes | 1.52 |
| | 1.66 |
| | | 1.04 |
|
| Workovers | 0.21 |
| | 0.55 |
| | | 0.46 |
|
| Depreciation, depletion and amortization | 9.44 |
| | 13.17 |
| | | 12.77 |
|
Lease operating expense for 2019 increased primarily due to an increase in net production coupled with the impact of additional costs for produced water disposal after our asset sale to KFM in the fourth quarter of 2018 and a non-cash charge to reduce the carrying value of certain supplies to realizable value.
Transportation and marketing expense for 2019 increased primarily due to increase in net production. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The increase is also due to an increase in committed capacity which went unused during 2019.
Production taxes for 2019 increased primarily due to an increase in production volumes and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.
Workovers for 2019 decreased primarily due to less workover projects undertaken due to our efforts to reduce costs. Workovers are associated with maintenance and other efforts to increase production.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Exploration expense: | | | | | | |
| Geological and geophysical costs | $ | 1,246 |
| | $ | 6,755 |
| | | $ | 2,440 |
|
| Exploratory dry hole expense | 23 |
| | 1,954 |
| | | — |
|
| Other exploration expense, including expired leases | 51,010 |
| | 24,374 |
| | | 4,504 |
|
| ARO settlements in excess of recorded liabilities | 75 |
| | 1,002 |
| | | 59 |
|
| Total exploration expense | $ | 52,354 |
| | $ | 34,085 |
| | | $ | 7,003 |
|
Exploration expense for 2019 increased primarily due to an increase in expired and expiring leases, primarily for those in Major and Kingfisher counties in Oklahoma. Geological and geophysical costs decreased as a result of headcount reductions.
Depreciation, depletion and amortization expense for 2019 decreased as a result of a significantly lower depletable base due to impairments recorded during 2018 and 2019.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Impairment of assets: | | | | | | |
| Impairment of unproved properties | $ | 31,023 |
| | $ | 742,065 |
| | | $ | — |
|
| Impairment of proved properties | 484,830 |
| | 1,291,647 |
| | | — |
|
| Impairment of operating lease right-of-use assets | 13,245 |
| | — |
| | | — |
|
| Impairment of other long-term assets | 27,329 |
| | — |
| | | — |
|
| Total impairment of assets | $ | 556,427 |
| | $ | 2,033,712 |
| | | $ | — |
|
Impairment of assets for 2019 consisted of impairment of our proved and unproved properties, operating lease right-of-use assets and a long-term prepaid asset. Our oil and gas properties were impaired during the third quarter of 2019 based on our impairment analysis resulting from our bankruptcy filing and further impaired during the fourth quarter of 2019 after taking into consideration the expected purchase price of the AMH Sale Transaction, net of estimated direct costs, for substantially all of our upstream assets. Operating lease right-of-use assets were impaired during the second quarter 2019 based on our inability to fully recover cash outflows due to lessors for certain unused office space. A further impairment of the remaining value of our operating lease right-of-use assets, as well as significant portion of a long-term prepaid asset, was taken as of December 31, 2019, due to the expected sale of substantially all of our assets, andwe do not anticipate any payments being required under the expected rejectionTRA.
Pre-Closing Assignment Agreement
Prior to the closing of certain leases and contracts that indicated we would not be ablethe Business Combination, Alta Mesa entered into an Assignment Agreement to fully recovertransfer to its existing owners (other than the carrying value of those assets. We believe the Buyer has the intent and ability to close the Sale Transactions.
For the 2018 Period, impairment largely related to a decrease in commodity prices, as well as the results of exploratory and development drilling and well performance, which reduced the value of our assets. A significant decline in spot and future estimated commodity prices late in the fourth quarter of 2018, and the impact of changes in our individual well reserve recovery estimates triggered a downward revision in the future cash flows expected to be generated by ourRiverstone Contributor) its remaining non-STACK oil and gas properties,assets and all liabilities associated therewith. Such existing owners agreed to indemnify Alta Mesa for any losses relating to the non-STACK assets, including any employment, environmental and tax liabilities.
We believe there is substantial doubt about their ability to honor the indemnification, which
requiredmay subject us to
reduceliabilities for the
carrying valuenon-STACK oil and gas assets. We currently cannot estimate the extent of
those propertiessuch liabilities and expect such liabilities, if any, to
estimated fair value.be addressed via our bankruptcy proceedings. |
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| General and administrative expense: | | | | | | |
| Employee-related costs | $ | 22,018 |
| | $ | 18,203 |
| | | $ | 1,032 |
|
| Equity-based compensation | 5,718 |
| | 20,000 |
| | | — |
|
| Professional fees | 8,289 |
| | 12,981 |
| | | 1,019 |
|
| Strategic costs | 8,116 |
| | — |
| | | — |
|
| Business Combination | — |
| | 23,717 |
| | | 17,040 |
|
| Severance costs | 4,865 |
| | 8,357 |
| | | — |
|
| Information technology | 4,002 |
| | 4,654 |
| | | — |
|
| Operating leases | 4,193 |
| | 3,267 |
| | | 208 |
|
| Provision for uncollectible receivables | 1,218 |
| | 22,438 |
| | | — |
|
| Other | 1,478 |
| | 1,118 |
| | | 1,935 |
|
| Total general and administrative expense | $ | 59,897 |
| | $ | 114,735 |
| | | $ | 21,234 |
|
GeneralMr. Chappelle, Mr. Ellis and administrative expense for 2019 decreased comparedcertain affiliates of Bayou City and HPS own an aggregate 10% voting interest in Alta Mesa Holdings GP, LLC (“Alta Mesa GP”). These individuals and entities were a party to a voting agreement with the 2018 Period primarily dueHigh Mesa and Alta Mesa GP, pursuant to (i) nonrecurring expenseswhich they have agreed to vote their interests in Alta Mesa GP as directed by High Mesa. In connection with the 2018 Period related toclosing of the Business Combination, the parties amended and professional fees for various advisors, (ii)restated the voting agreement to include SRII Opco as a $22.4 million provision for certainparty 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 and attorney-in-fact with respect to any voting matters related party receivables (including notes receivable) we assessed as uncollectible, and (iii) higher equity-based compensation expense and severance costs associated with the departure of certain members of executive managementto their respective interests in late 2018. General and administrative expense during 2019 also included costs for legal and strategic financial advisory services associated with financial restructuring activities, including negotiations with representatives of our lenders and other third
parties, as well as severance costs associated with a reductionAlta Mesa GP. The voting agreement will continue in force in early 2019. All professional fees incurred fromuntil SRII Opco elects to terminate the filing of the Initial Bankruptcy Petitions forward, and directly relatedagreement or, with respect to the bankruptcy, are reportedeach existing owner individually, such existing owner no longer owns a voting interest in Reorganization items, net.
Below is a reconciliation of our loss from continuing operations before income taxes to Upstream Adjusted EBITDAX:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Loss from continuing operations before income taxes | $ | (597,510 | ) | | $ | (2,076,370 | ) | | | $ | (7,116 | ) |
| | | | | | |
|
| Interest expense | 49,823 |
| | 38,265 |
| | | 5,511 |
|
| Depreciation, depletion and amortization | 120,617 |
| | 133,554 |
| | | 11,670 |
|
| Exploration | 52,354 |
| | 34,085 |
| | | 7,003 |
|
| Loss (gain) on unrealized hedges | 19,386 |
| | (28,714 | ) | | | (8,959 | ) |
| Loss (gain) on sale of property and equipment | — |
| | 388 |
| | | — |
|
| Impairment of assets | 556,427 |
| | 2,033,712 |
| | | — |
|
| Equity-based compensation | 5,718 |
| | 20,000 |
| | | — |
|
Provision for uncollectible related party receivables(1) | 886 |
| | 22,438 |
| | | — |
|
| Severance costs | 4,865 |
| | — |
| | | — |
|
| Strategic costs | 8,116 |
| | — |
| | | — |
|
| Business combination | — |
| | 23,717 |
| | | 17,040 |
|
| Non-cash lease operating expense | 3,835 |
| | — |
| | | — |
|
| Reorganization items, net | (449 | ) | | — |
| | | — |
|
| Upstream Adjusted EBITDAX | $ | 224,068 |
| | $ | 201,075 |
| | | $ | 25,149 |
|
_________________
| |
(1) | Represents a provision for the estimated uncollectibility of certain related party receivables (including notes receivable). |
Other (Income) Expense
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Alta Mesa RBL | $ | 24,541 |
| | $ | 2,807 |
| | | $ | 815 |
|
| 2024 Notes | 27,453 |
| | 35,273 |
| | | 3,281 |
|
| Bond premium amortization | (3,432 | ) | | (4,512 | ) | | | — |
|
| Deferred financing cost amortization | 195 |
| | 221 |
| | | 171 |
|
| Other | 1,066 |
| | 4,476 |
| | | 1,244 |
|
| Total interest expense | 49,823 |
| | 38,265 |
| | | 5,511 |
|
| Interest income | (154 | ) | | (1,983 | ) | | | (172 | ) |
| Reorganization items, net | (449 | ) | | — |
| | | — |
|
| Total other (income) expense, net | $ | 49,220 |
| | $ | 36,282 |
| | | $ | 5,339 |
|
Interest expense for 2019 increased due to higher average debt balances outstanding under the Alta Mesa RBL coupled with higher default and borrowing base deficiency interest rates beginning in September 2019. We ceased accruing interest on the 2024GP.
Promissory Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.
Reorganization items, net |
| | | |
| (in thousands) | Year Ended December 31, 2019 |
| Unamortized deferred financing fees and premiums | $ | (24,725 | ) |
| Terminated contracts | (1,435 | ) |
| Legal and other professional advisory fees | 25,711 |
|
| Reorganization items, net | $ | (449 | ) |
Midstream Segment Results of Operations
Revenue
Our Midstream revenue was primarily derived from product sales, gas gathering and processing, crude oil gathering, and produced water gathering and disposal fees.
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Sales of gathered production | $ | 37,195 |
| | $ | 31,506 |
|
| Midstream revenue | 84,763 |
| | 63,199 |
|
| Produced water disposal fees | 24,988 |
| | 5,320 |
|
| Total Midstream revenue | $ | 146,946 |
| | $ | 100,025 |
|
| |
| |
|
| KFM gas volumes (MMcf) | 49,147 |
| | 35,058 |
|
| KFM crude oil gas volumes (Mbbls) | 1,104 |
| | 1,739 |
|
| KFM produced water gathering volumes (Mbbls) | 25,295 |
| | 5,320 |
|
Sales of gathered production for 2019 increased compared to the 2018 Successor Period due to increased oil and gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. We process the gas on behalf of the producer and sell the resulting gas, condensate and NGLs at a market price. Product sales are recognized when sold to the third-party purchaser. Amounts recognized in product sales are dependent on whether we are acting in the role of a principal or agent in our contracts with our customers. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense.
Midstream revenue for 2019 increased compared to the 2018 Successor Period due to increased gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. The level of drilling and well completion activity of our customers impacts the fees we earn from the throughput of gas we gather and process and the volume of crude oil we gather each period.
Produced water disposal fees resulted from the acquisition of produced water disposal assets from AltaReceivables - High Mesa during the fourth quarter of 2018. The level of drilling and well completion activity of our customers impacts the amount of fees we generate from the produced water that we gather and dispose of.
Expenses
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Midstream operating | $ | 24,719 |
| | $ | 15,221 |
|
| Cost of sales for purchased gathered production | 34,529 |
| | 31,247 |
|
| Transportation and processing | 9,659 |
| | 9,911 |
|
| Workovers | 537 |
| | — |
|
| Depreciation and amortization | 11,675 |
| | 27,388 |
|
| Impairment of assets: | | | |
| Impairment of Cimarron investment | — |
| | 15,963 |
|
| Impairment of property and equipment | 348,597 |
| | 68,407 |
|
| Impairment of operating lease right-of-use assets | 269 |
| | — |
|
| Impairment of intangible assets | — |
| | 394,999 |
|
| Impairment of goodwill | — |
| | 691,970 |
|
| Total Midstream impairment of assets | 348,866 |
| | 1,171,339 |
|
| General and administrative | 35,427 |
| | 14,025 |
|
| Total operating expenses | $ | 465,412 |
| | $ | 1,269,131 |
|
Midstream operating expense for 2019 increased compared to the 2018 Successor Period due to operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes processed, which led to higher variable plant operating costs.
Cost of sales for purchased gathered production for 2019 increased compared to the 2018 Successor Period due to increase in sales of gathered production. The margin for net sales increased due to plant efficiency improvements during 2019.
Depreciation and amortization expense for 2019 decreased compared to the 2018 Successor Period due to amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was coupled with a decrease in tangible asset depreciation as a result of significantly lower book asset values due to impairments recorded during 2018 and 2019, partially offset by depreciation on the produced water assets acquired in the fourth quarter of 2018.
Impairment of assets for 2019 decreased compared to the 2018 Successor Period. During 2019, property and equipment was impaired during the third quarter of 2019 as a result of our impairment analysis arising from the bankruptcy filing by Alta Mesa. We further impaired these assets during the fourth quarter 2019, after taking into consideration the expected purchase price of the KFM Sale Transaction, net of estimated direct costs, for substantially all of our assets. We believe the Buyer has the intent and ability to close the Sale Transactions.
During the 2018 Successor Period, impairment of assets consisted of write-downs of our equity method investment in Cimarron, certain property and equipment and full write-offs of the carrying amount of our intangible assets and goodwill. The fair value of the Midstream segment was negatively impacted by a significant decline in commodity prices in the fourth quarter of 2018 and the related impact on our and other producers’ future upstream operating plans. Our upstream operations contribute a significant portion of the volumetric throughput to the KFM plant. A decline in such throughput negatively impacts future expected profitability, and thus, fair value of the Midstream segment.
We reduced the carrying amount of our investment in Cimarron to adjust its carrying value to fair value at December 31, 2018 due to our decision to abandon the project.
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| General and administrative expenses: | | | |
| Employee-related costs | $ | 14,569 |
| | $ | 8,199 |
|
| Equity-based compensation | 694 |
| | 1,190 |
|
| Professional fees | 2,092 |
| | 1,743 |
|
| Strategic costs | 11,479 |
| | 10 |
|
| Severance costs | 2,162 |
| | — |
|
| Information technology | 214 |
| | 240 |
|
| Operating leases | 348 |
| | 253 |
|
| Provision for uncollectible receivable | 2,310 |
| | — |
|
| Other | 1,559 |
| | 2,390 |
|
| Total general and administrative expense | $ | 35,427 |
| | $ | 14,025 |
|
General and administrative expense for 2019 increased compared to the 2018 Successor Period primarily due to increased employee-related costs allocable to KFM, increased costs for legal and strategic financial advisory services associated with financial restructuring activities, and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility. Moreover, following a reassessment of 2019 activity levels, we implemented a reduction in force program during 2019, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.
Below is a reconciliation of our loss from continuing operations before income taxes to Midstream Adjusted EBITDA:
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Loss from continuing operations before income taxes | $ | (323,975 | ) | | $ | (1,174,131 | ) |
| | | |
|
| Interest expense | 11,636 |
| | 5,031 |
|
| Depreciation and amortization | 11,675 |
| | 27,388 |
|
| Loss on sale of property and equipment | 106 |
| | — |
|
| Impairment of assets | 348,866 |
| | 1,171,339 |
|
| Equity-based compensation | 694 |
| | 1,190 |
|
| Severance costs | 2,162 |
| | — |
|
| Strategic costs | 11,479 |
| | — |
|
| Provision for uncollectible related party receivables | 2,310 |
| | — |
|
| Gain on equity method investment | (5,503 | ) | | — |
|
| Adjusted EBITDA | $ | 59,450 |
| | $ | 30,817 |
|
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| KFM Credit Facility | $ | 10,728 |
| | $ | 3,062 |
|
| Deferred financing cost amortization | 463 |
| | 305 |
|
| Other | 445 |
| | 1,664 |
|
| Total interest expense | 11,636 |
| | 5,031 |
|
| Interest income | (17 | ) | | (6 | ) |
| Equity in earnings of unconsolidated subsidiaries | (6,216 | ) | | — |
|
| Total other (income) expense | $ | 5,403 |
| | $ | 5,025 |
|
Interest expense for 2019 increased primarily due to higher average debt balances outstanding under the KFM Credit Facility. Other interest primarily relates to commitment fees.
Equity in earnings of unconsolidated subsidiaries represents our share of earnings due to our equity method investment in Cimarron. In November 2019, we obtained control of Cimarron. As a result, we recognized a gain of $5.5 million to adjust our investment to the fair value of the assets to be received upon consolidating this entity.
Liquidity and Capital Resources
Our principal requirements for capital are to fund our day-to-day operations and to satisfy our contractual obligations. During 2019, our main sources of liquidity and capital resources came from cash on hand, operating cash flow and borrowings under the Alta Mesa RBL and KFM Credit Facility.
On September 11, 2019, the Initial Debtors filed for bankruptcy protection, which constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default. As of December 31, 2019, we had $355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $1.9 million in outstanding letters of credit.
In August 2019, our lenders elected to exercise their right to an off-cycle borrowing base redetermination, whereby they reduced our borrowing base from $370.0 million to $200.0 million. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments. Subsequent to Alta Mesa’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows Alta Mesa to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.
On September 23, 2019, KFM received a reservation of rights letter from its lenders asserting an event of default under the KFM Credit Agreement, thereby eliminating its ability to access capital under its revolver, pending a cure of the alleged event of default. As a result, KFM utilized cash on hand and cash flow from operations to fund required expenditures and satisfy contractual obligations during the fourth quarter 2019.
On January 12, 2020, the KFM Debtors filed for bankruptcy protection under Chapter 11 of the bankruptcy code, which constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder. Under the Bankruptcy Code, the lenders under the KFM Credit Facility are stayed from taking any action against the KFM Debtors as a result of an event of default. As of December 31, 2019, outstanding borrowings under the KFM Credit Facility totaled $224.0 million and there were no outstanding letters of credit. Subsequent to KFM’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows KFM to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.
Alta Mesa and KFM expect to sell substantially all of their assets no later than mid-April 2020 for a combined price of $320.0 million before deductions for direct costs. Following the expected sale, we intend to provide certain transition services to th
e Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
2024 Notes
Alta Mesa has$500.0 million in aggregate principal amount of outstanding notes bearing interest at 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.
Related Party Receivables
On September 29, 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured on February 28, 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $1.7 million. HMS defaulted under the terms of thatthe $1.5 million promissory note when itthe note was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory note receivable from HMS which maturesmatured on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, 2019 and 2018, the note receivable amounted to $11.7 million. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2019, we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.
Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.
In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “HMI Agreement”) with HMI with respect to its non-STACK assets. Under the HMIJoint Development Agreement during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the HMI Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.
Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (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 reimbursable pursuant to the HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million for costs and expenses incurred on HMI’s behalf. Subsequent to
year-end 2018, we billed HMI $0.8 million for incremental MSA costs incurred and have received approximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable. We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result, as of December 31, 2019, we have recognized an allowance for uncollectible accounts of $9.8 million to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.
Tax Receivable Agreement
We are party to a Tax Receivable Agreement (“TRA”) with SRII Opco, High Mesa, and Riverstone VI Alta Mesa Holdings, L.P. This agreement generally provides for the payment by us of 85% of the amount of any realized net cash savings, in U.S. federal, state and local income tax 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 AMR 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 KFM or otherwise used in KFM’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 TRA. Also, under the TRA, we retain the benefit of the remaining 15% of these cash savings.
As of December 31, 2019, there had been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units then held by High Mesa were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash savings in U.S. federal, state and local income tax, multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, 2019, we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have not recorded a liability for such at this time. As a result of our bankruptcy filings and the expected sale of substantially all of our assets, we do not anticipate any payments being required under the TRA.
Cash Flows
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash from operating activities | $ | 143,798 |
| | $ | 86,809 |
| | | $ | 26,336 |
|
| Cash from investing activities | (320,329 | ) | | (560,547 | ) | | | (37,913 | ) |
| Cash from financing activities | 244,724 |
| | 501,205 |
| | | 16,932 |
|
| Net increase in cash, cash equivalents and restricted cash | $ | 68,193 |
| | $ | 27,467 |
| | | $ | 5,355 |
|
Cash from operating activities
Cash provided by operating activities during 2019 increased compared to the 2018 Successor Period and the 2018 Predecessor Period primarily due to collection of receivables, which were higher at December 31, 2018 as compared to December 31, 2019 due to our bankruptcy filing. Additionally, our 2018 operating cash flow was burdened by nonrecurring costs associated with (i) certain administrative services provided to HMI and its subsidiaries that were subsequently determined to be uncollectible and (ii) the Business Combination. Partially offsetting these factors was an increased use of cash in 2019 associated with prepayment of legal and professional advisor fees relating to our bankruptcy filing as well as a prepayment of transportation fees under a long-term customer contract.
Cash from investing activities
Cash used in investing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period, primarily due to significantly reduced capital expenditures resulting from the suspension of our development activities in conjunction with Alta Mesa’s bankruptcy filing in September 2019. The 2018 Successor Period included activity relating to the Business Combination, which was funded through proceeds withdrawn from a trust account that was established upon the initial public offering of the Company in 2017.
Cash from financing activities
Cash provided by financing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period. Our ability to borrow funds during 2019 was terminated upon Alta Mesa’s bankruptcy filing in September 2019 and restrictions imposed by the lenders under the KFM Credit Facility due to an alleged default. During the 2018 Successor Period, we received $400.0 million from the sale of our Class A Common Stock and warrants pursuant to a forward purchase agreement, which was partially offset by deferred underwriting payments and certain other costs associated with the Business Combination plus repurchases of our common stock.
Risk Management Activities — Commodity Derivative Instruments
In connection with Alta Mesa’s bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts in September 2019 for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. After September 2019, we held no open derivative positions.
Off-Balance Sheet Arrangements
As of December 31, 2019, other than as described below, we had no guarantees of third-party obligations. Alta Mesa was contingently liable for bonds posted in the aggregate amount of $1.3 million, primarily to cover future abandonment costs, and $1.9 million in letters of credit provided under the Alta Mesa RBL. Upon closing of the expected Sale Transactions, we would be released from these obligations. We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.
Alta Mesa and HMI are both parties to a payment and indemnity agreement with our current surety provider in connection with regulatory bonds executed prior to the Business Combination covering STACK and non-STACK assets. The surety bonds in place covered by the payment and indemnity agreement for HMI non-STACK properties total approximately $15 million. The surety asserts that Alta Mesa is jointly and severally liable pursuant to the payment and indemnity agreement, but Alta Mesa disputes that claim asserting that the Business Combination evidenced separation between the STACK and non-STACK assets thereby removing any exposure of Alta Mesa to liabilities associated with non-STACK assets. As a result of the dispute, the surety has filed liens on Alta Mesa and KFM assets in order to establish a claim against Alta Mesa in the event HMI is unable to post collateral or otherwise satisfy its obligations with respect to the surety bonds. The closing of the expected Sale Transactions is not expected to impact these outstanding surety bonds.
Critical Accounting Policies and Estimates
Our financial statements are prepared in accordance with GAAP. In connection with preparing our financial statements, we are required to make assumptions and estimates about future events and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in our audited financial statements included elsewhere in this Annual Report. We believe that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.
Oil and Gas Reserves
Policy Description
Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In calculating cash inflows for reserves, we use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling.
In calculating cash outflows for reserves, we use well costs and operating costs prevailing during the preceding year, but more heavily weighted toward recent demonstration levels, which are then held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental policies.
We limit our future development program to only those wells that we expect to be developed within five years of their initial recognition.
Judgments and Assumptions
All of our reserve information is based on estimates. Estimates of gas reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil and gas. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of oil and gas that are ultimately recovered.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. We have used estimates of proved reserves in the past to assess for impairment, and we also rely heavily on them in the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate and resulting expense will increase, resulting in a decrease in net income. A decline in estimates of proved reserves have also caused us in previous periods to perform an impairment analysis to determine whether the carrying amount of oil and gas properties exceeds fair value, which would result in an impairment charge, reducing net income.
Successful Efforts Method of Accounting for Oil and Gas Properties
Policy Description
Oil and gas producing activities are accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Accounting policies include:
Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts incurred to obtain a mineral interest or right in a property, such as a lease, options to lease, and related broker and other fees. Properties are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire or are sold.
Proved Oil and Gas Properties — Costs incurred to lease, drill, complete and equip proved reserves 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 — Our unproved properties consist of leasehold and other capital costs incurred for properties for which no proved reserves have been identified. In determining whether unproved property is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation of the property and the remaining
lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated resource potential and, combined with a market approach, estimate fair value of our properties. Our cash flow estimates for probable and possible resource potential is reduced by additional risk-weighting factors. We then reduce the carrying amount of unproved properties, if higher, to estimated fair value.
The capitalized costs of proved oil and gas properties are reviewed at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level or the likely cash flow from sale of the assets to the carrying value of the assets. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value. For our proved oil and gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
Judgments and Assumptions
Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
Key assumptions used to determine the undiscounted future cash flows could include estimates of future production, timing of new wells coming on line, differentials, net estimated operating costs, anticipated capital expenditures and future commodity prices. Our discussion of the judgments inherent in reserve estimation above has information with direct bearing on the judgments surrounding our depletion calculation and impairment analysis. However, in conducting our impairment analysis, we also replace pricing assumptions with future price estimates and we include values for our probable and possible resource potential in determining fair value.
Lower net undiscounted cash flows can result in the carrying amount of our oil and gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in levels and timing of capital and operating expenses, and changes in production among other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly which can negatively impact forward commodity prices, causing lower undiscounted net cash flows. Similarly, future capital and lease operating costs are uncertain and can change quickly based on regional oil and gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, among other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans.
Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.
Recent Accounting Pronouncements
Our audited financial statements in Item 8 contain a description of recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Not required.
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Alta Mesa Resources, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Alta Mesa Resources, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (Successor), changes in partners’ capital (Predecessor) and cash flows for the year ended December 31, 2019, the period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the year ended December 31, 2019, the period from February 9, 2018 to December 31, 2018 (Successor), and the period from January 1, 2018 to February 8, 2018 (Predecessor), in conformity with U.S. generally accepted accounting principles.
Going Concern
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations and its liquidity outlook, along with the risks and uncertainties related to its Chapter 11 voluntary petition, raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. 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, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting 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.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2018.
Houston, Texas
March 5, 2020
ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Revenue | | | | | | |
| Oil | $ | 328,386 |
| | $ | 323,299 |
| | | $ | 30,972 |
|
| Natural gas | 53,693 |
| | 43,407 |
| | | 4,276 |
|
| Natural gas liquids | 40,026 |
| | 43,039 |
| | | 4,000 |
|
| Sales of gathered production | 37,195 |
| | 31,506 |
| | | — |
|
| Midstream revenue | 30,590 |
| | 27,460 |
| | | — |
|
| Other | 10,330 |
| | 4,762 |
| | | 888 |
|
| Operating revenue | 500,220 |
| | 473,473 |
| | | 40,136 |
|
| Gain on sale of assets | 1,382 |
| | 4,751 |
| | | 840 |
|
| Gain (loss) on derivatives | (11,744 | ) | | (10,247 | ) | | | 6,663 |
|
| Total revenue | 489,858 |
| | 467,977 |
| | | 47,639 |
|
| Operating expenses | | | | | | |
| Lease operating | 63,755 |
| | 56,827 |
| | | 4,408 |
|
| Transportation, processing and marketing | 21,042 |
| | 19,293 |
| | | 3,725 |
|
| Midstream operating | 24,719 |
| | 15,221 |
| | | — |
|
| Cost of sales for purchased gathered production | 34,529 |
| | 31,247 |
| | | — |
|
| Production taxes | 19,455 |
| | 16,865 |
| | | 953 |
|
| Workovers | 3,189 |
| | 5,563 |
| | | 423 |
|
| Exploration | 52,354 |
| | 34,085 |
| | | 7,003 |
|
| Depreciation, depletion and amortization | 132,292 |
| | 160,942 |
| | | 11,670 |
|
| Impairment of assets | 905,293 |
| | 3,205,051 |
| | | — |
|
| General and administrative | 107,655 |
| | 131,052 |
| | | 21,234 |
|
| Total operating expenses | 1,364,283 |
| | 3,676,146 |
| | | 49,416 |
|
| Operating income | (874,425 | ) | | (3,208,169 | ) | | | (1,777 | ) |
| Other income (expense) | | | | | | |
| Interest expense | (61,459 | ) | | (43,296 | ) | | | (5,511 | ) |
| Interest income and other | 243 |
| | 2,049 |
| | | 172 |
|
| Equity in earnings of unconsolidated subsidiaries | 6,216 |
| | — |
| | | — |
|
| Reorganization items, net | (197 | ) | | — |
| | | — |
|
| Total other income (expense), net | (55,197 | ) | | (41,247 | ) | | | (5,339 | ) |
| Loss from continuing operations before income taxes | (929,622 | ) | | (3,249,416 | ) | | | (7,116 | ) |
| Income tax expense (benefit) | — |
| | (69 | ) | | | — |
|
| Loss from continuing operations | (929,622 | ) | | (3,249,347 | ) |
| | (7,116 | ) |
| Loss from discontinued operations, net of tax | — |
| | — |
| | | (7,746 | ) |
| Net loss | (929,622 | ) | | (3,249,347 | ) | | | $ | (14,862 | ) |
| Net loss attributable to non-controlling interest | (479,084 | ) | | (1,724,648 | ) | | |
|
|
| Net loss attributable to Alta Mesa Resources, Inc. stockholders | $ | (450,538 | ) | | $ | (1,524,699 | ) |
| |
|
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| | | | | | | |
| Net loss per common share attributable to Alta Mesa Resources, Inc. stockholders: | | | | | | |
| Basic and diluted | $ | (2.48 | ) | | $ | (8.71 | ) | | |
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares and per share data)
|
| | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| ASSETS | | | | |
| Current assets | | | | |
| Cash and cash equivalents | $ | 95,367 |
| | | $ | 26,854 |
|
| Restricted cash | 681 |
| | | 1,001 |
|
| Accounts receivable, net | 61,187 |
| | | 87,842 |
|
| Other receivables | 1,344 |
| | | 6,331 |
|
| Related party receivables | — |
| | | 3,341 |
|
| Prepaid expenses and other | 8,047 |
| | | 1,125 |
|
| Derivatives | — |
| | | 16,423 |
|
| Total current assets | 166,626 |
| | | 142,917 |
|
| Property and equipment | | | | |
| Oil and gas properties, successful efforts method, net | 215,352 |
| | | 763,337 |
|
| Other property and equipment, net | 107,028 |
| | | 444,269 |
|
| Total property and equipment, net | 322,380 |
| | | 1,207,606 |
|
| Other assets | | | | |
| Operating lease right-of-use assets, net | — |
| | | — |
|
| Equity method investment | — |
| | | 1,100 |
|
| Deferred financing costs, net | 1,581 |
| | | 3,195 |
|
| Deposits and other long-term assets | 7,993 |
| | | 65 |
|
| Derivatives | — |
| | | 2,947 |
|
| Total other assets | 9,574 |
| | | 7,307 |
|
| Total assets | $ | 498,580 |
|
| | $ | 1,357,830 |
|
The accompanying notes are an integral part of these financial statements.
|
| | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | |
| Current liabilities | | | | |
| Current portion of debt | $ | 224,000 |
| | | $ | 690,123 |
|
| Accounts payable and accrued liabilities | 64,137 |
| | | 247,439 |
|
| Advances from non-operators | 811 |
| | | 5,193 |
|
| Advances from related party | 3,175 |
| | | 9,839 |
|
| Asset retirement obligations, current portion | 34 |
| | | 2,079 |
|
| Operating lease liability, current portion | 88 |
| | | — |
|
| Derivatives | — |
| | | 1,710 |
|
| Total current liabilities not subject to compromise | 292,245 |
| | | 956,383 |
|
| Long-term liabilities | | | | |
| Asset retirement obligations, net of current portion | 13,149 |
| | | 9,473 |
|
| Long-term debt, net | — |
| | | 174,000 |
|
| Operating lease liabilities, net of current portion | 189 |
| | | — |
|
| Derivatives | — |
| | | 180 |
|
| Other long-term liabilities | 3,360 |
| | | 1,667 |
|
| Total long-term liabilities not subject to compromise | 16,698 |
| | | 185,320 |
|
| Liabilities subject to compromise | 896,862 |
| | | — |
|
| Total liabilities | 1,205,805 |
| | | 1,141,703 |
|
| Commitments and contingencies (Note 19) |
| | |
|
| Preferred stock, $0.0001 par value | | | | |
| Class A: 1,000,000 shares authorized; 3 shares issued; 2 outstanding | — |
| | | — |
|
| Class B: 1,000,000 shares authorized; 1 share issued and outstanding | — |
| | | — |
|
| Stockholders’ equity | | | | |
| Common stock, $0.0001 par value | | | | |
| Class A: 1,200,000,000 shares authorized; 182,774,952 and 180,072,227 issued and outstanding at December 31, 2019 and December 31, 2018, respectively. | 18 |
| | | 18 |
|
| Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at December 31, 2019 and December 31, 2018, respectively. | 20 |
| | | 20 |
|
| Additional paid in capital | 1,512,716 |
| | | 1,503,382 |
|
| Accumulated deficit | (1,983,351 | ) | | | (1,532,813 | ) |
| Total stockholders’ equity | (470,597 | ) | | | (29,393 | ) |
| Noncontrolling interest | (236,628 | ) | | | 245,520 |
|
| Total equity | (707,225 | ) | | | 216,127 |
|
| Total liabilities and stockholders’ equity | $ | 498,580 |
| | | $ | 1,357,830 |
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash flows from operating activities: | | | | | | |
| Net loss | $ | (929,622 | ) | | $ | (3,249,347 | ) | | | $ | (14,862 | ) |
| Adjustments to reconcile net loss to cash from operating activities: | | | | | | |
| Depreciation, depletion and amortization | 132,292 |
| | 160,942 |
| | | 12,554 |
|
| Non-cash lease expense | 3,122 |
| | — |
| | | — |
|
| Provision for uncollectible receivables | 3,528 |
| | 22,438 |
| | | — |
|
| Impairment of assets | 905,293 |
| | 3,205,051 |
| | | 5,560 |
|
| Non-cash reorganization items, net | (26,160 | ) | | — |
| | | — |
|
| Amortization of deferred financing costs | 658 |
| | 526 |
| | | 171 |
|
| Amortization of debt premium | (3,432 | ) | | (4,512 | ) | | | — |
|
| Equity-based compensation expense | 6,412 |
| | 22,025 |
| | | — |
|
| Non-cash exploration expense | 43,412 |
| | 26,055 |
| | | 4,575 |
|
| (Gain) loss on derivatives | 11,744 |
| | 10,247 |
| | | (6,663 | ) |
| Cash settlements of derivatives | 7,642 |
| | (38,961 | ) | | | (2,296 | ) |
| Premium paid on derivatives | (1,906 | ) | | — |
| | | — |
|
| Interest converted into debt related to Founder notes | — |
| | — |
| | | 103 |
|
| Interest added to notes receivable from related party | — |
| | (949 | ) | | | (85 | ) |
| Loss on sale of property and equipment | 106 |
| | 388 |
| | | 1,923 |
|
| Equity in earnings of unconsolidated subsidiaries | (6,216 | ) | | — |
| | | — |
|
| Impact on cash from changes in: | | | | | | |
| Accounts receivable | 26,323 |
| | 18,011 |
| | | (21,184 | ) |
| Other receivables | 4,988 |
| | (4,045 | ) | | | (662 | ) |
| Related party receivables and payables | 145 |
| | (11,468 | ) | | | (117 | ) |
| Prepaid expenses and other assets | (29,078 | ) | | 11,149 |
| | | (591 | ) |
| Advances from related party | (6,664 | ) | | (37,668 | ) | | | 24,116 |
|
| Settlement of asset retirement obligations | (234 | ) | | (1,610 | ) | | | (63 | ) |
| Accounts payable, accrued liabilities and other liabilities | 4,216 |
| | (41,463 | ) | | | 23,857 |
|
| Operating lease obligations | (2,771 | ) | | — |
| | | — |
|
| Cash from operating activities | 143,798 |
| | 86,809 |
| | | 26,336 |
|
| Cash flows from investing activities: | | | | | | |
| Capital expenditures | (327,567 | ) | | (762,760 | ) | | | (36,695 | ) |
| Acquisitions, net of cash acquired | — |
| | (823,778 | ) | | | (1,218 | ) |
| Proceeds withdrawn from Trust Account | — |
| | 1,042,742 |
| | | — |
|
| Proceeds from (Contribution to) equity method investment and other | 7,238 |
| | (17,063 | ) | | | — |
|
| Proceeds from sale of assets | — |
| | 312 |
| | | — |
|
| Cash from investing activities | (320,329 | ) | | (560,547 | ) | | | (37,913 | ) |
| Cash flows from financing activities: | | | | | | |
| Proceeds from long-term debt borrowings | 254,362 |
| | 431,500 |
| | | 60,000 |
|
| Repayments of long-term debt | (9,496 | ) | | (273,565 | ) | | | (43,000 | ) |
| Payment of taxes withheld on equity-based compensation awards | (142 | ) | | — |
| | | — |
|
| Deferred financing costs paid | — |
| | (3,722 | ) | | | — |
|
| Purchase and retirement of Class A common shares | — |
| | (14,750 | ) | | | — |
|
| Capital contributions (distributions) | — |
| | — |
| | | (68 | ) |
| Proceeds from issuance of Class A shares | — |
| | 400,000 |
| | | — |
|
| Repayment of sponsor note | — |
| | (2,000 | ) | | | — |
|
| Repayment of deferred underwriting compensation | — |
| | (36,225 | ) | | | — |
|
| Redemption of Class A common shares | — |
| | (33 | ) | | | — |
|
| Cash from financing activities | 244,724 |
| | 501,205 |
| | | 16,932 |
|
| Net increase in cash, cash equivalents and restricted cash | 68,193 |
| | 27,467 |
| | | 5,355 |
|
| Cash, cash equivalents and restricted cash, beginning of period | 27,855 |
| | 388 |
| | | 4,990 |
|
| Cash, cash equivalents and restricted cash, end of period | $ | 96,048 |
| | $ | 27,855 |
| | | $ | 10,345 |
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)
(in thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | | | | | Total | | | | |
| | Class A | | Class B | | Class C | | Paid-In | | Accumulated | | Stockholders’ | | Noncontrolling | | Total |
| | Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | Capital | | Deficit | | Equity | | Interests | | Equity |
| Balance at February 8, 2018 | 3,862 |
| | $ | — |
| | 25,875 |
| | $ | 3 |
| | — |
| | $ | — |
| | $ | 3,106 |
| | $ | (8,114 | ) | | $ | (5,005 | ) | | $ | — |
| | $ | (5,005 | ) |
| Conversion of common shares from Class B to Class A at closing of Business Combination | 25,875 |
| | 3 |
| | (25,875 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Class A common shares released from possible redemption | 99,638 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 996,374 |
| | — |
| | 996,384 |
| | — |
| | 996,384 |
|
| Class A common shares redeemed | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (33 | ) | | — |
| | (33 | ) | | — |
| | (33 | ) |
| Sale of Class A common shares | 40,000 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| | 399,996 |
| | — |
| | 400,000 |
| | — |
| | 400,000 |
|
| Class C common shares issued in connection with the closing of the Business Combination | — |
| | — |
| | — |
| | — |
| | 213,402 |
| | 21 |
| | (21 | ) | | — |
| | — |
| | — |
| | — |
|
| Noncontrolling interest in SRII Opco issued in the Business Combination | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,058,635 |
| | 2,058,635 |
|
| Balance at February 9, 2018 | 169,372 |
| | 17 |
| | — |
| | — |
| | 213,402 |
| | 21 |
| | 1,399,422 |
| | (8,114 | ) | | 1,391,346 |
| | 2,058,635 |
| | 3,449,981 |
|
| Additional Class C common shares issued in connection with the settlement of the purchase consideration in the business combination | — |
| | — |
| | — |
| | — |
| | 1,109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Noncontrolling interest in SRII Opco assumed in the business combination | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8,758 |
| | 8,758 |
|
| Redemption of noncontrolling interests and Class C common shares for Class A common shares | 12,341 |
| | 1 |
| | — |
| | — |
| | (12,341 | ) | | (1 | ) | | 105,593 |
| | — |
| | 105,593 |
| | (105,599 | ) | | (6 | ) |
| Purchase and retirement of Class A common shares and related sale of SRII Opco Common Units | (3,102 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (25,589 | ) | | — |
| | (25,589 | ) | | 10,839 |
| | (14,750 | ) |
| Restricted stock awards vested | 1,944 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,465 |
| | — |
| | 2,465 |
| | (2,465 | ) | | — |
|
| Equity-based compensation expense | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 22,025 |
| | — |
| | 22,025 |
| | — |
| | 22,025 |
|
| Shares withheld/retired for taxes on equity awards | (483 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (534 | ) | | — |
| | (534 | ) | | — |
| | (534 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,524,699 | ) | | (1,524,699 | ) | | (1,724,648 | ) | | (3,249,347 | ) |
| Balance at December 31, 2018 | 180,072 |
| | 18 |
| | — |
| | — |
| | 202,170 |
| | 20 |
| | 1,503,382 |
| | (1,532,813 | ) | | (29,393 | ) | | 245,520 |
| | 216,127 |
|
| Conversion of commons shares from Class C shares to Class A shares | 2,182 |
| | — |
| | — |
| | — |
| | (2,182 | ) | | — |
| | 2,756 |
| | — |
| | 2,756 |
| | (2,756 | ) | | — |
|
| Restricted stock awards vested, net of taxes | 521 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 166 |
| | — |
| | 166 |
| | (308 | ) | | (142 | ) |
| Equity-based compensation expense | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6,412 |
| | — |
| | 6,412 |
| | — |
| | 6,412 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (450,538 | ) | | (450,538 | ) | | (479,084 | ) | | (929,622 | ) |
| Balance at December 31, 2019 | 182,775 |
| | $ | 18 |
| | — |
| | $ | — |
| | 199,988 |
| | $ | 20 |
| | $ | 1,512,716 |
| | $ | (1,983,351 | ) | | $ | (470,597 | ) | | $ | (236,628 | ) | | $ | (707,225 | ) |
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
(in thousands)
|
| | | |
| | Predecessor |
| Balance, December 31, 2017 | $ | 154,445 |
|
| Distribution of non-STACK oil and gas assets, net of associated liabilities | 43,482 |
|
| Net loss | (14,862 | ) |
| Balance, February 8, 2018 | $ | 183,065 |
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2019
NOTE 1—DESCRIPTION OF BUSINESS
Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generates revenue primarily through long-term, fee-based contracts.
We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the IPO and a private sale of warrants were placed in a trust account and were used on February 9, 2018, to acquire the interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination” at which time we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.
On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).
On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.
The Initial and Additional Debtors continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).
The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.
The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.
In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.
The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.
Our Class A Common Stock and public warrants to purchase Class A Common Stock, sold as part of the shares issued in the IPO, were initially traded on the NASDAQ Capital Market (“NASDAQ”), but due to our failure to continue to meet the NASDAQ’s listing requirements, trading in our stock and public warrants was suspended in September 2019, and are now traded over the counter on the OTC Pink Marketplace under the symbols “AMRQQ” and “AMRWQ”, respectively. In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa Holdings, LP (“High Mesa”). The results of operations of the non-STACK assets and related liabilities are reflected as discontinued operations in the Predecessor portion of our financial statements.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Bankruptcy Accounting
As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Initial Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy process have been classified as “liabilities subject to compromise” on our balance sheet at December 31, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on its consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on our historical financial statements.
Also, as described further in Note 3, on January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases. The Additional Debtors also continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
Ability to Continue as a Going Concern
AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.
As described further in Note 1, we expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.
Basis of Accounting and Presentation
These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss), stockholders’ equity or partners’ capital.
As a result of the Business Combination, we are the acquirer for accounting purposes and Alta Mesa and KFM are the acquirees. The identifiable assets acquired and liabilities assumed were recorded at their estimated fair values, which were pushed down to each entity. As a result, our financial statements and certain footnotes separate our presentation into two distinct periods, the periods before the consummation of the Business Combination (“Predecessor Periods”) and the period after that date (the “Successor Period”). Our financial statements reflect Alta Mesa as the “Predecessor” for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, reflecting the consolidation of Alta Mesa and KFM beginning on February 9, 2018. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. The 2018 Predecessor Period and the periods prior to January 1, 2018 are collectively referred to as the “Predecessor Periods”.
As noted above, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa in connection with the closing of the Business Combination. We determined the non-STACK oil and gas assets and related liabilities are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements.
Principles of Consolidation
The financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated. Noncontrolling interest (“NCI”) represents third-party ownership interests in SRII Opco and is presented as a component of equity. The portion of SRII Opco earnings that are not attributable to the Company are separately presented in our statements of operations.
Segment Reporting (Successor)
We operate in 2 reportable business segments: (i) Upstream and (ii) Midstream. Alta Mesa conducts our Upstream activities and owns proved and unproved oil and gas properties. KFM operates our Midstream segment and owns gas gathering, processing and produced water disposal assets and crude oil gathering and transportation assets. Both segments are conducted in the United States and all revenue was derived from customers located in the United States.
Use of Estimates
Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.
Other significant estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, federal and state taxes and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. 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. We regularly maintain cash balances that exceed federally insured amounts, but we have experienced no losses associated with these amounts.
Restricted Cash
Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2019, and 2018, our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma.
Accounts Receivable
Our receivables arise primarily from (i) the sale of our production, (ii) joint interest owners’ portion of operating costs for properties in which we are the operator, and (iii) for midstream services provided to third-party customers. The purchasers of our production and our midstream customers are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production.
We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers.
Property and Equipment
Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties
and become subject to depletion, or when we abandon plans to develop leases are impaired, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion.
Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties.
Accounting policies for Midstream and other assets include:
Other Property and Equipment — Other property and equipment, such as land, buildings, plant equipment, assets associated with produced water disposal, vehicles, office furniture and office equipment, are recorded at cost. Maintenance, repairs and minor renewals are expensed as incurred. Plant and equipment also includes costs for our cryogenic gas processing facility along with gas gathering pipelines and compression, including rights of way, and a crude oil gathering system and crude oil storage facility.
Other important accounting policies affecting property and equipment include:
Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves.
Through December 31, 2019, we depreciated our Midstream property and equipment using the straight-line method over the estimated useful lives of the assets, which included 35 years for our produced water disposal assets, processing plant and pipelines and 25 years for our compressors. Leasehold improvements were depreciated over the shorter of their useful lives or the term of the lease. Vehicles and office furniture and office equipment were depreciated over their estimated useful lives, ranging from three years to seven years. As a result of the expected sale of substantially all of our assets no later than mid-April 2020, we will depreciate any assets that are not to be acquired by the Buyer over our expected wind-down period, expected to be less than one year.
Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value.
We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate.
We evaluate whether the value of all other long-lived assets, including our midstream assets, is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset, changes to planned throughput or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections or the likely cash flow from sale of the assets compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis, an analysis from outside professional advisors or, if the long-lived asset is to be sold, utilizing the likely cash flow from sale as the best estimate of fair value.
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 or expiring leases with no expected development, delay rentals, gains or losses on settlement of asset retirement obligations, salaries for geologically-focused employees and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves. If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if the assessment of commerciality is ongoing.
Equity Method Investment
We account for investments that we do not control, but in which we can exercise significant influence, using the equity method of accounting. Such investments are originally recorded at our acquisition cost. The investment is adjusted by our proportionate share of the investee’s net income, increased by contributions made and decreased by distributions received.
We assess the carrying value of our equity method investments for impairment when indicators exist indicating an impairment may be other-than-temporary. If an impairment is deemed to be other-than-temporary, we adjust the carrying value to fair value, if lower.
In November 2019, we acquired the remaining 50% interest in Cimarron Express Pipeline, LLC (“Cimarron”), which we previously accounted for under the equity method, and consolidated this entity beginning in November 2019.
Deferred Financing Costs
Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. Prior to the bankruptcy filing by the Initial Debtors, the costs associated with the Alta Mesa RBL were amortized over the term of the Alta Mesa RBL as additional interest expense, with the remaining unamortized costs written off to “reorganization items, net” in our statement of operations upon the bankruptcy filing. The costs associated with the KFM Credit Facility are reported as non-current assets and are amortized over the term of the KFM Credit Facility as additional interest expense but were written off in January after it filed for bankruptcy. During the Predecessor Periods, costs associated with the issuance of our 7.875% senior unsecured notes maturing in December 2024 (the “2024 Notes”) were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. These Predecessor defined financing costs were eliminated with the Business Combination’s adjustment to 2024 Notes to fair value.
Acquisitions
Business combinations are accounted for using the acquisition method. The results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition.
Intangible Assets
In connection with the acquisition of KFM, we recognized the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach. These intangible assets, all of which related to the Midstream segment, had finite lives and were subject to amortization utilizing an accelerated attrition method to approximate the benefit received over their economic lives.
Goodwill
We recognized goodwill as the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired in the Business Combination. Goodwill was not amortized but was subject to periodic impairment assessment at least annually, or whenever events and circumstances indicated an impairment may exist.
Asset Retirement Obligations
We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred. The
fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The asset retirement cost is recognized as depletion or depreciation over the life of the asset. Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations. Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment.
There are no material legal or contractual obligations relating to dismantlement, decommissioning or removal of our Midstream assets, other than for certain of our produced water assets, for which asset retirement obligations have been established as of December 31, 2019.
Bond Premium on 2024 Notes
In connection with the Business Combination, we estimated the fair value of our $500.0 million 2024 Notes at $533.6 million. The excess fair value above the face value was recognized as a bond premium, which was being amortized as a reduction in interest expense over the remaining term of the notes prior to the time of the bankruptcy filing by the Initial Debtors. The remaining unamortized premium was written off to “reorganization items, net” in our consolidated statement of operations upon the Initial Debtors’ bankruptcy filing.
Derivatives
We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty.
Income Taxes
Successor
Deferred income taxes are provided for the temporary differences between the basis of assets and liabilities for financial reporting and income tax purposes. We classify deferred tax assets and liabilities as noncurrent.
We assess the ability to realize our deferred tax assets on a quarterly basis. Deferred tax assets may be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. A valuation allowance is established to reduce deferred tax assets to the amount expected to be realized when we determine that it is more likely than not that some or all of the deferred tax assets are not realizable.
We are also subject to the Texas margin tax, which is considered an income-based tax. We recognize tax (current and deferred) based on taxable income, as determined using the rules for the margin tax as a component of our income tax provision.
We assess uncertain tax positions using a two-step process. If we determine it is more likely than not that the income tax position will be sustained upon examination by the taxing authorities, we recognize the largest amount that is greater than 50% likely to be realized upon ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We did not record any liabilities for uncertain tax positions as of December 31, 2019 or December 31, 2018.
We record interest and penalties for the taxation, as a component of income tax expense. We did not incur any material tax interest or penalties for any period presented.
Alta Mesa’s tax returns for the years ended December 31, 2016 and forward remain open for examination, but none are currently under examination by the relevant authorities.
Predecessor
Alta Mesa historically elected to be treated as an individual partnership for tax purposes. Accordingly, its items of income, expense, gains and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was recognized by the Predecessor.
Predecessor net income (loss) for financial statement purposes differed significantly from taxable income (loss) reported 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 Alta Mesa’s amended and restated partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes could not be readily determined due to some tax basis differences being determined at the partner level and Alta Mesa’s lack of information about each unitholder’s tax attributes in Alta Mesa.
Revenue Recognition
Predecessor -
Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented.
Successor (Upstream) -
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.
Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.
Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Moreover, as part of the process of applying the five-step model, we also evaluated AMH’s and KFM’s arrangement in following the principal-versus-agent guidance under ASC 606. As a principal seller to the customer, revenues are recognized on a gross basis, and as an agent, revenue are recognized on a net basis.
Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, AMH is considered to be the principal seller to its customers, and we record sales and related expenses on a gross basis upon satisfaction of our performance obligations.
Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. However, instances in which all or a significant percentage of the proceeds from the sale must be returned to the producer, we are deemed to be the agent. As a result, the purchase and sale are presented as a net transaction with our margin included in gathering and processing revenue. When evaluating the principal-versus-agent guidance under ASC 606 and its impact on AMH and KFM, all facts and circumstances are considered and judgment is often required in making this determination.
Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that
affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables.
Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties or lease operating expense. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.
We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented.
We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.
Midstream -
We have the following significant revenue sources each of which we consider to be a distinct service and each of which possesses a single performance obligation:
Natural gas gathering, processing and sale of residue gas and NGLs for Alta Mesa and third parties;
Crude oil gathering for Alta Mesa; and
Produced water gathering and disposal for Alta Mesa and third parties.
We provide our services pursuant to a variety of contracts that set forth our fees, including in certain contracts, the percentage of the proceeds from the sale of our customers’ products in addition to the specified fee. Our services are typically billed on a monthly basis in the month following services or delivery of the product with payment typically due within 30 days. We do not offer extended payment terms and we have no contracts with financing components. Our gathering contracts have initial terms that span multiple years up to the life of the dedicated properties. Our most significant produced water contract has an initial term of 15 years.
We recognize revenue principally under contracts that contain one or more of the following arrangements:
Fee-based arrangements
Revenue for fee-based arrangements are recognized over the contract term with revenue recognized for each month of service based on the volumes delivered by the customer. Both natural gas gathering and processing plus crude oil gathering services are recognized in gathering and processing revenues. Produced water services are recognized as produced water disposal fees.
For service rates that are unchanged over the contract term or escalate only due to inflation, we recognize revenue at the rate in effect during the month of service. We have instances where we also charge supplemental fees for an early period of time during the contract term and this revenue is recognized over the expected period of customer benefit, which is generally the remaining term of the contract. The difference between the amount billed and collected for such early term fees billed during the initial contract term and the amount recorded as revenue is deferred and recognized as contract liabilities. At December 31, 2019 and 2018, we had recognized a deferral of $3.4 million and $1.7 million, respectively, of these early term fees which is included in other long-term liabilities.
Percent-of-proceeds arrangements
Under our percent-of-proceeds arrangements, we generally receive natural gas from producers at or near the wellhead, move it through our gathering system, process it to separate the gas and liquid products and sell the resulting gas and NGLs to third parties. We then remit to the producers an agreed-upon percentage of the actual proceeds received from sales. The margins we earn are directly related to the volumes that flow through our system and the price at which we are able to sell the products.
We evaluate our percent-of-proceeds arrangements with customers against the principal/agent provisions of the underlying contract. For those arrangements where we possess control of the commodity after processing and act as principal in the sale, we record sales revenue equal to the gross price received and we recognize the cost paid to the purchaser as cost of sales of
gathered purchased production. For those percent-of-proceeds arrangements where we do not control the products after processing, because substantially all of the sales proceeds are paid to the producer, we act as an agent for the producer and only recognize the net margin that we earn within sales of gathered production.
In limited instances, we may also receive products as consideration under percent-of-proceeds agreements. We recognize revenue for the products received at their fair value in the month of service.
Sale of gathered production
We sell gas, NGLs and condensate purchased from our customers to third parties pursuant to short term arrangements at market-based prices adjusted for location and quality differentials. These sales are recognized at the point (i) when we satisfy our performance obligation by transferring control of the product to the purchaser at the specified delivery point, (ii) when amounts are determinable and (iii) when we determine that collectibility is probable. The determination of the point control is transferred relies upon a variety of facts and circumstances including: the purchaser’s ability to use the products, the transfer of significant risks and rewards, our right to payment and transfer of legal title. The cost to purchase the underlying products is recognized when we obtain control of the product, but is generally concurrent with their sale.
Also, we may sell products to other midstream companies pursuant to off-take agreements. Under these contracts, we evaluate whether we control the products during processing and whether the processor controls the products in their sale to the ultimate purchaser. For those contracts where we do not control the products during processing, we recognize revenue on their sale to the midstream company based on the price received net of processing fees earned by the midstream company. For those contracts where we control the products during processing and where we direct their sale, we recognize revenue on the gross price received within sales of gathered production and we recognize the fees paid to the midstream company as transportation, processing and marketing expense.
Equity-Based Compensation
In 2018, we granted various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees.
The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date.
Service-based restricted stock awards are valued using the market price of our Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of Class A Common Stock at the later of grant date and when all performance-based criteria are determined.
We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is 3.0 years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense.
Fair Value Hierarchy
Fair value is 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 within our principal market.
There are three levels of the fair value hierarchy:
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• | Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities.
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• | Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active.
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• | Level 3 —Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques.
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We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets.
We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. Our outstanding borrowings under the Alta Mesa RBL have been classified as liabilities subject to compromise at December 31, 2019 and the outstanding borrowings under the KFM Credit Facility will be classified similarly following the January 2020 bankruptcy filing by the Additional Debtors as full recovery by our lenders following the expected sale of substantially all of our assets is unlikely.
Earnings Per Share
Basic earnings per share is calculated by dividing earnings available to Class A common stockholders by the weighted average number of shares outstanding during each period. In periods where we report negative earnings, basic and diluted earnings per share are identical.
The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding SRII Opco Common Units and corresponding shares of its outstanding Class C Common Stock, as well as outstanding warrants and the treasury stock method to determine the potential dilutive effect of restricted stock, restricted stock units and stock options.
Recently Issued Accounting Standards Applicable to Us
Adopted
As described further in Note 5, we adopted Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease, and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term, effective January 1, 2019.
Not Yet Adopted
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today and would have been effective for us beginning January 2023. We made no determination as to the impact of this new standard on our financial position or results of operations upon adoption.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard, on a prospective basis, beginning January 2020.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. Adoption of this standard will not impact our financial position or results of operations.
NOTE 3 - CHAPTER 11 PROCEEDINGS
Voluntary Reorganization Under Chapter 11
On September 11, 2019, the Initial Debtors filed for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court granted a motion seeking joint administration of the Chapter 11 cases.
In January 2020, the Additional Debtors filed for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Chapter 11 cases. The Debtors operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court.
The filing of the Debtors’ bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors to recover, collect or secure a claim arising prior to the bankruptcy filings. Accordingly, although the bankruptcy filing triggered defaults of the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, the creditors are generally stayed from taking any actions as a result of such defaults. Absent an order of the Bankruptcy Court, substantially all of the Initial Debtors’ prepetition liabilities are subject to compromise under the Bankruptcy Code at December 31, 2019 and substantially all of the Additional Debtors’ prepetition liabilities became subject to compromise under the Bankruptcy Code beginning in January 2020.
In September 2019, an official committee of unsecured creditors was appointed. In October 2019, the Bankruptcy Court approved proposed bidding procedures and the dates for an auction and a hearing to approve the sale or sales of assets under Section 363 of the Bankruptcy Code. The auction was held on January 15, 2020, at which a winning bid was selected for substantially all of Alta Mesa and KFM’s assets totaling $320.0 million before certain direct sales costs. The Sale Transactions are expected to close no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
Initial Orders and Other Filings
In September 2019, the Bankruptcy Court approved measures that allow the Initial Debtors to stabilize their businesses and operations. Similar orders requested by the Additional Debtors were approved by the Bankruptcy Court in January 2020. The Debtors are authorized to use cash collateral of their lenders, but the Debtors must adhere to a budget and meet certain milestones.
Liabilities Subject to Compromise
Liabilities subject to compromise at December 31, 2019 represented the Initial Debtors’ remaining prepetition liabilities that have been allowed or that the Initial Debtors anticipate will be allowed as claims in its Chapter 11 cases. The amounts represent the estimated obligations to be resolved in connection with their Chapter 11 proceedings. The differences between the estimate and the claims filed will be evaluated and resolved in connection with the claims resolution process during the pendency of Chapter 11 proceedings.
Following are the components of liabilities subject to compromise:
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| (in thousands) | December 31, 2019 |
| Alta Mesa RBL | $ | 355,943 |
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| 2024 Notes | 500,000 |
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| Accounts payable and accrued liabilities | 20,315 |
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| Accrued interest payable on 2024 Notes | 9,516 |
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| Operating lease liabilities | 11,088 |
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| Liabilities subject to compromise | $ | 896,862 |
|
Reorganization Items
The Initial Debtors have incurred and, along with the Additional Debtors, are expected to continue to incur significant costs associated with the bankruptcy.
Components of reorganization items, net included are:
|
| | | |
| (in thousands) | Year Ended December 31, 2019 |
| Unamortized deferred financing fees and premiums | $ | 24,725 |
|
| Terminated contracts | 1,435 |
|
| Legal and other professional advisory fees | (26,357 | ) |
| Reorganization items, net | $ | (197 | ) |
Interest Expense
The Company did not record interest expense on its 2024 Notes after the Initial Debtors’ filing for bankruptcy. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.
Executory Contracts
Under the Bankruptcy Code, the Debtors may reject certain executory contracts with the approval of the Bankruptcy Court. Generally, the rejection of an executory contract is treated as a prepetition breach of that contract, therefore the Debtors are relieved of performing their future obligations under such executory contract, but the contract counterparty is entitled to file a general unsecured claim for damages.
Combined Financial Information of Initial Debtors
Combined Statement of Operations
|
| | | |
| (in thousands) | Year Ended December 31, 2019 |
| Revenue | |
| Oil | $ | 328,386 |
|
| Natural gas | 53,693 |
|
| Natural gas liquids | 40,026 |
|
| Other | 1,471 |
|
| Operating revenue | 423,576 |
|
| Gain on sale of assets | 1,488 |
|
| Loss on derivatives | (11,744 | ) |
| Total revenue | 413,320 |
|
| Operating expenses | |
| Lease operating | 79,884 |
|
| Transportation and marketing | 70,324 |
|
| Production taxes | 19,455 |
|
| Workovers | 2,652 |
|
| Exploration | 52,354 |
|
| Depreciation, depletion and amortization | 120,617 |
|
| Impairment of assets | 556,427 |
|
| General and administrative | 71,823 |
|
| Total operating expenses | 973,536 |
|
| Operating income | (560,216 | ) |
| Other income (expenses) | |
| Interest expense | (49,823 | ) |
| Interest income | 154 |
|
| Reorganization items, net | (197 | ) |
| Total other income (expense), net | (49,866 | ) |
| Loss from continuing operations before income taxes | (610,082 | ) |
| Income tax provision (benefit) | — |
|
| Net loss | $ | (610,082 | ) |
Combined Balance Sheet
|
| | | |
| (in thousands) | December 31, 2019 |
| ASSETS | |
| Current assets | |
| Cash and cash equivalents | $ | 81,669 |
|
| Restricted cash | 681 |
|
| Accounts receivable, net | 49,256 |
|
| Other receivables | 1,311 |
|
| Related party receivables, net | 17,586 |
|
| Prepaid expenses and other current assets | 6,340 |
|
| Total current assets | 156,843 |
|
| Property and equipment, net | |
| Oil and gas properties, successful efforts method | 215,352 |
|
| Other property and equipment | 23,210 |
|
| Total property and equipment, net | 238,562 |
|
| Other assets | |
| Investment in subsidiary | 1,505,533 |
|
| Operating lease right-of-use assets, net | — |
|
| Deferred financing costs, net | — |
|
| Deposits and other long-term assets | 6,116 |
|
| Total other assets | 1,511,649 |
|
| Total assets | $ | 1,907,054 |
|
| | |
| LIABILITIES AND PARTNERS’ CAPITAL | |
| Current liabilities | |
| Accounts payable and accrued liabilities | $ | 58,858 |
|
| Accounts payable - related parties | 19,425 |
|
| Advances from non-operators | 811 |
|
| Advances from related party | 3,175 |
|
| Asset retirement obligations, current portion | 34 |
|
| Total current liabilities | 82,303 |
|
| Long-term liabilities | |
| Asset retirement obligations, net of current portion | 12,995 |
|
| Total long-term liabilities | 12,995 |
|
| Liabilities subject to compromise | 896,862 |
|
| Total liabilities | 992,160 |
|
| Partners’ capital | 914,894 |
|
| Total liabilities and partners’ capital | $ | 1,907,054 |
|
Combined Statement of Cash Flows
|
| | | |
| (in thousands) | Year Ended December 31, 2019 |
| Cash flows from operating activities: | |
| Net loss | $ | (610,082 | ) |
| Adjustments to reconcile net loss to cash from operating activities: | |
| Depreciation, depletion and amortization | 120,617 |
|
| Non-cash lease expense | 2,981 |
|
| Provision for uncollectible receivables | 1,218 |
|
| Impairment of assets | 556,427 |
|
| Non-cash reorganization items, net | (26,160 | ) |
| Amortization of deferred financing costs | 195 |
|
| Amortization of debt premium | (3,432 | ) |
| Equity-based compensation expense | 5,718 |
|
| Non-cash exploration expense | 43,412 |
|
| (Gain) loss on derivatives | 11,744 |
|
| Cash settlements of derivatives | 7,642 |
|
| Cash paid for derivatives | (1,906 | ) |
| Impact on cash from changes in: | |
| Accounts receivable | 18,783 |
|
| Other receivables | 4,957 |
|
| Related party receivables | 3,651 |
|
| Prepaid expenses and other assets | (25,716 | ) |
| Advances from related party | (6,647 | ) |
| Settlement of asset retirement obligations | (234 | ) |
| Accounts payable, accrued liabilities and other liabilities | 22,373 |
|
| Operating lease obligations | (2,636 | ) |
| Cash from operating activities | 122,905 |
|
| Cash flows from investing activities: | |
| Capital expenditures | (249,955 | ) |
| Distribution received from subsidiary | 691 |
|
| Cash from investing activities | (249,264 | ) |
| Cash flows from financing activities: | |
| Proceeds from long-term debt borrowings | 199,362 |
|
| Repayments of long-term debt | (4,496 | ) |
| Payment of taxes withheld on equity-based compensation awards | (142 | ) |
| Cash from financing activities | 194,724 |
|
| Net increase in cash, cash equivalents and restricted cash | 68,365 |
|
| Cash, cash equivalents and restricted cash, beginning of period | 13,985 |
|
| Cash, cash equivalents and restricted cash, end of period | $ | 82,350 |
|
NOTE 4 — IMPAIRMENT OF ASSETS
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Upstream | | | | | | |
| Impairment of unproved properties | $ | 31,023 |
| | $ | 742,065 |
| | | $ | — |
|
| Impairment of proved properties | 484,830 |
| | 1,291,647 |
| | | — |
|
| Impairment of operating lease right-of-use assets | 13,245 |
| | — |
| | | — |
|
| Impairment of other long-term assets | 27,329 |
| | — |
| | | — |
|
| Total Upstream impairment of assets | 556,427 |
| | 2,033,712 |
| | | — |
|
| Midstream | | | | | | |
| Impairment of Cimarron investment | — |
| | 15,963 |
| | | — |
|
| Impairment of property and equipment | 348,597 |
| | 68,407 |
| | | — |
|
| Impairment of operating lease right-of-use assets | 269 |
| | — |
| | | — |
|
| Impairment of intangible assets | — |
| | 394,999 |
| | | — |
|
| Impairment of goodwill | — |
| | 691,970 |
| | | — |
|
| Total Midstream impairment of assets | 348,866 |
| | 1,171,339 |
| | | — |
|
| | | | | | | |
| Total impairment of assets | $ | 905,293 |
| | $ | 3,205,051 |
| | | $ | — |
|
Impairment of Proved and Unproved Properties
The Initial Debtors filed for bankruptcy protection in September 2019. The sales price per the AMH PSA is $232.0 million (with a January 1, 2020 effective date) for substantially all of our oil and gas properties and certain other upstream property and equipment, resulting in total impairment expense of $515.9 million for our proved and unproved oil and gas properties and $13.1 million for certain other upstream property and equipment during 2019.
During the late fourth quarter of 2018, we experienced a combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations. We determined these factors indicated possible impairment of our assets. Following our analysis of impairment, we recognized impairment charges of $2.0 billion in 2018 to our proved and unproved oil and gas properties using an income approach supplemented by a market approach for our unproved properties.
Impairment of Operating Lease Right-of-Use Assets
During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease our unused office space resulting from the consolidation but have since suspended those efforts in connection with our bankruptcy filing. Additionally, as a result of the expected Sale Transactions, we concluded that all remaining operating lease right-of-use assets were also not recoverable based on expected rejection of those leases in bankruptcy. As a result, we recognized charges of $13.2 million and $0.3 million, respectively, to fully impair all remaining Upstream and Midstream operating lease right-of-use assets at December 31, 2019. This impairment had no impact on our lease liability.
Impairment of Other Long-Term Assets
In addition to the impairment of certain other upstream property and equipment described above, we also recognized impairment expense of $14.2 million associated with a long-term asset relating to a prepayment of certain transportation fees under a long-term customer contract. As part of our bankruptcy proceedings, we expect this contract will be rejected and have determined that recovery of this prepayment is unlikely.
Impairment of equity method investment
As the late-2018 outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and agreed with our partner to abandon the project. We conducted an impairment analysis resulting in recognition of an impairment charge of $16.0 million to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018. In November 2019, we acquired the remaining 50% interest in Cimarron and consolidated this entity thereafter.
Impairment of property and equipment and intangible assets
The sales price per the KFM PSA is $88.0 million (with a January 1, 2020 effective date) for substantially all of our midstream property and equipment, resulting in total impairment expense of $348.6 million during 2019.
In the fourth quarter of 2018, we performed a quantitative assessment of our Midstream property and equipment and intangible assets, which included the use of an income approach which determined that the future undiscounted cash flows associated with our Midstream long-lived assets and intangible assets were below the combined carrying value of those assets. The cash flows used in the income approach were largely determined based on expected future gathering volumes which are dedicated to our gathering and processing facilities and are considered Level 3 inputs. We also considered the overall utilization of the processing plant and applied downward adjustments to the cost approach to account for decreased plant utilization. Based on an estimate of fair value using a discounted cash flow income approach, we determined that the carrying value of our Midstream property and equipment was in excess of its fair value and that the intangible assets were fully impaired at December 31, 2018. Accordingly, we recognized impairment charges in 2018 of $68.4 million to reduce the carrying value of our Midstream property and equipment to fair value and $395.0 million to reduce the remaining carrying value of our intangible assets to zero.
Impairment of goodwill
We performed a quantitative assessment to determine if the goodwill attributable to the Midstream segment was impaired as of December 31, 2018. Our assessment included the use of (i) an income approach to calculate the present value of estimated future discounted cash flows and (ii) a market approach to assess the value of the Midstream segment based on market participant multiples applied to the segment’s 2019 estimated cash generation. The cash flows used in the income approach were largely determined based on expected future production volumes of our Upstream segment, much of which is dedicated to the Midstream segment’s gathering and processing facilities. The income approach also used a market participant-based discount rate. Each of our assumptions regarding earnings, cash flows and discount rates were based mainly on Level 3 unobservable inputs. The results from the income approach and the market approach were appropriately weighted to recognize an impairment charge to eliminate the remaining carrying value of our goodwill.
NOTE 5 — ADOPTION OF ASU NO. 2016-02, LEASES
ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on our balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method as of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.
We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not currently sublease any of our ROU assets.
Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.
Upon adoption, we selected the following practical expedients:
|
| | |
Practical expedient package | | We did not reassess whether any expired or existing contracts are, or contain, leases. |
| | We did not reassess the lease classification of any expired or existing leases. |
| | We did not reassess initial direct costs of any expired or existing leases. |
| | |
Hindsight practical expedient | | We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. |
| | |
Easement expedient | | We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. |
| | |
Combining lease and non-lease components expedient | | We elected to account for lease and non-lease components as a single component. |
| | |
Short-term lease expedient | | We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet. |
As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At December 31, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.0 years and the weighted-average discount rate applied was 14.5%.
Lease Costs
|
| | | | |
| (in thousands) | | Year Ended December 31, 2019 |
| Operating lease cost | | $ | 3,122 |
|
| Variable lease cost | | 1,250 |
|
| Short-term lease cost | | 4,410 |
|
| Total lease cost | | $ | 8,782 |
|
| | | |
| Reported in: | | |
| Lease operating expense | | $ | 4,241 |
|
| General and administrative expense | | 4,541 |
|
| Total lease cost | | $ | 8,782 |
|
Remaining Operating Lease Liability Payments as of December 31, 2019
|
| | | | |
| Fiscal year | | (in thousands) |
| 2020 | | $ | 2,256 |
|
| 2021 | | 2,209 |
|
| 2022 | | 2,329 |
|
| 2023 | | 2,321 |
|
| 2024 | | 2,367 |
|
| Thereafter | | 8,219 |
|
| Total lease payments | | 19,701 |
|
| Less: imputed interest | | (8,336 | ) |
| Less: reclassification to liabilities subject to compromise | | (11,088 | ) |
| Present value of operating lease liabilities | | $ | 277 |
|
| | | |
| Current portion of operating lease liabilities | | $ | 88 |
|
| Operating lease liabilities, net of current portion | | 189 |
|
| Present value of operating lease liabilities | | $ | 277 |
|
NOTE 6 — RECEIVABLES
Accounts Receivable
|
| | | | | | | | |
| (in thousands) | December 31, 2019 | | | December 31, 2018 |
| Production and processing sales and fees | $ | 40,858 |
| | | $ | 51,004 |
|
| Joint interest billings | 12,845 |
| | | 18,147 |
|
Pooling interest (1) | 7,901 |
| | | 18,786 |
|
| Allowance for doubtful accounts | (417 | ) | | | (95 | ) |
| Total accounts receivable, net | $ | 61,187 |
| | | $ | 87,842 |
|
_________________
| |
(1) | Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties. |
Related Party Receivables
|
| | | | | | | |
| (in thousands) | December 31, 2019 | | December 31, 2018 |
| Related party receivables | $ | 12,144 |
| | $ | 12,376 |
|
| Allowance for doubtful accounts | (12,144 | ) | | (9,035 | ) |
| Related party receivables, net | — |
| | 3,341 |
|
| | | | |
| Notes receivable from related parties | 13,403 |
| | 13,403 |
|
| Allowance for doubtful accounts | (13,403 | ) | | (13,403 | ) |
| Notes receivable from related parties, net | — |
| | — |
|
| Related party receivables, net | $ | — |
| | $ | 3,341 |
|
At December 31, 2019, we had receivables, including notes receivable from HMI totaling approximately $23.2 million. Because HMI disputes its obligations under the promissory notes with us and challenges other amounts due us, we had fully reserved the outstanding receivables at December 31, 2019 based upon our assessment regarding collectibility.
Additionally, at December 31, 2019, we had receivables of $2.3 million from KFM’s former owner, KFM Holdco, LLC (“KFM Holdco”), relating to transaction costs paid on KFM Holdco’s behalf before the Business Combination. During 2019, we fully
reserved this receivable based upon our assessment regarding collectibility. We have filed suit against KFM Holdco to seek payment for this receivable.
Management Services Agreement with HMI
|
| | | |
| (in thousands) | |
| HMI related party receivable at December 31, 2018 | $ | 10,066 |
|
| Additions | 832 |
|
| Payments | (1,073 | ) |
| HMI related party receivable at December 31, 2019 | 9,825 |
|
Allowance for doubtful accounts(1) | (9,825 | ) |
| Balance at December 31, 2019, net | $ | — |
|
_________________
| |
(1) | $9.0 million of the allowance was recognized during the 2018 Successor Period. |
Our management services agreement with HMI (the “HMI Agreement”) was terminated effective January 31, 2019. During the transition period, HMI agreed to pay us (i) for all services performed, (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 reimbursable pursuant to the HMI Agreement. As of December 31, 2019, and December 31, 2018, approximately $9.8 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes or amounts that may become due pursuant to indemnification obligations which became more uncertain when HMI filed for bankruptcy protection in January 2020. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.8 million and $9.0 million as of December 31, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances.
We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of December 31, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.
Promissory notes receivable
High Mesa Services, LLC (“HMS”), a subsidiary of HMI, defaulted under the terms of a promissory note with us when it did not pay us on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of December 31, 2019 and December 31, 2018.
In addition, we have a note receivable from HMS which matured on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. HMI disputes its obligations under the note. As of December 31, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods. We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes.
We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors have responsibility to address any potential conflicts of interest with respect to this matter.
Activity in our allowances for doubtful accounts for trade and related party receivables was as follows:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Trade receivables: | | | | | | |
| Balance at beginning of period | $ | 95 |
| | $ | 415 |
| | | $ | 415 |
|
| Charged to expense | 332 |
| | 25 |
| | | — |
|
| Deductions | (10 | ) | | (345 | ) | | | — |
|
| Balance at end of period | $ | 417 |
| | $ | 95 |
| | | $ | 415 |
|
| | | | | | | |
| Related party receivables: | | | | | | |
| Balance at beginning of period | $ | 22,438 |
| | $ | — |
| | | $ | — |
|
| Charged to expense | 3,196 |
| | 22,438 |
| | | — |
|
| Deductions | (87 | ) | | — |
| | | — |
|
| Balance at end of period | $ | 25,547 |
| | $ | 22,438 |
| | | $ | — |
|
NOTE 7 — EARNINGS PER SHARE
|
| | | | | | | |
| (in thousands, except shares and per share data) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Net loss attributable to AMR Class A common stockholders | $ | (450,538 | ) | | $ | (1,524,699 | ) |
| | | | |
| Weighted average Class A common shares outstanding (Basic and Diluted) | 181,636,795 |
| | 175,151,969 |
|
| | | | |
| Basic and diluted loss per common share attributable to AMR common stockholders | $ | (2.48 | ) | | $ | (8.71 | ) |
During 2019, approximately 201.0 million shares of Class C Common Stock, 63.0 million of warrants and 5.1 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.
During the 2018 Successor Period, approximately 99.9 million shares of Class C Common Stock, 63.0 million of warrants and 6.2 million of aggregate stock options, restricted stock and restricted stock units, were excluded from the calculation of diluted earnings per share as their effect would have been anti-dilutive.
NOTE 8 — SUPPLEMENTAL CASH FLOW INFORMATION
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Supplemental cash flow information: | | | | | | |
| Cash paid for interest | $ | 56,683 |
| | $ | 52,017 |
| | | $ | 1,145 |
|
| Cash paid for income taxes | 706 |
| | 1,573 |
| | | — |
|
| Non-cash investing and financing activities: | | | | | | |
| Increase in asset retirement obligations | 853 |
| | 5,665 |
| | | — |
|
| Increase (decrease) in accruals or payables for capital expenditures | (155,681 | ) | | 39,997 |
| | | 4,896 |
|
| Increase in withholding tax accruals for share-based compensation | 142 |
| | 534 |
| | | — |
|
| Distribution of non-STACK assets, net of liabilities | — |
| | — |
| | | 43,482 |
|
| Equity issued in Business Combination | — |
| | 2,067,393 |
| | | — |
|
| Release of common stock from possible redemption | — |
| | 996,384 |
| | | — |
|
| Other | 78 |
| | (6 | ) | | | — |
|
NOTE 9 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES
We made no acquisitions or divestitures during 2019.
2018 Activity
On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by (i) the Contribution Agreement (“AM Contribution Agreement”), dated August 16, 2017, with Alta Mesa, High Mesa, High Mesa Holdings GP, LLC, the sole general partner of High Mesa, Alta Mesa GP, and, solely for certain provisions therein, the equity owners of High Mesa, (ii) the Contribution Agreement (the “KFM Contribution Agreement”), dated August 16, 2017, with KFM Holdco, KFM, and, solely for certain provisions therein, the equity owners of KFM Holdco; and (iii) the Contribution Agreement (“the Riverstone Contribution Agreement”) dated August 16, 2017 with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”). The AM Contribution Agreement, the KFM Contribution Agreement and the Riverstone Contribution Agreement are together referred to as the “Contribution Agreements”. High Mesa, KFM Holdco and the Riverstone Contributor are together referred to as the “Contributors”.
Pursuant to the Contribution Agreements,2016, SRII Opco acquired (a) (i) all of the limited partner interests in Alta Mesa and (ii) 100% of the economic interests and 90% of the voting interests in Alta Mesa GP, ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in KFM (the “KFM Contribution”). SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR. As a result of the Business Combination, our only significant asset was our ownership at that time of an approximate 44.2% partnership interest in SRII Opco. SRII Opco owns all of the economic interests in each of Alta Mesa and KFM. SRII Opco was deemed to be a variable interest entity (“VIE”) and we were deemed to be the primary beneficiary of SRII Opco and have control of SRII Opco through our voting control of SRII Opco GP. Accordingly, we consolidate both SRII Opco and SRII Opco GP, including their consolidated subsidiaries, in our financial results.
Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa.
At the closing of the Business Combination:
we issued (i) 40,000,000 shares of our Class A Common Stock and (ii) warrants to purchase 13,333,333 shares of our 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 $1,338 million in cash representing (i) the proceeds from the Forward Purchase Agreement and (ii) the net proceeds, after redemptions and payment of deferred underwriting compensation, of the Trust Account, less transaction fees, amounts due Silver Run Sponsor II, LLC. (our “Sponsor”) and reimbursement of seller transaction fees and costs to SRII Opco, in exchange for (i) 169,371,730 of the common units (approximately 44.2%) representing limited partner interests in SRII Opco (the “SRII Opco Common Units”) and (ii) 62,966,651 warrants to purchase SRII Opco Common Units (“SRII Opco Warrants”);
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 KFM;
we agreed to cause SRII Opco to issue up to 59,871,031 SRII Opco Common Units to High Mesa and KFM Holdco if the earn-out conditions were met pursuant to the terms of the Contribution Agreements;
the Company 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 each such Contributor;
SRII Opco distributed $814.8 million to KFM Holdco in partial payment for the ownership interests in KFM; and
SRII Opco entered into an amended and restated 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 our 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. The Contributors 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 canceled.
During 2019 and 2018, the Contributors redeemed 2,181,600 and 12,341,076, respectively of SRII Opco Common Units for an equal number of shares of Class A Common Stock through a direct exchange, whereby the combined 14,522,676 SRII Opco Common Units are now owned by us, and we issued an equal number of shares of our Class A Common Stock to them and canceled the related shares of our Class C Common Stock. Additionally, during 2018 we sold 3,101,510 of our Common Units in SRII Opco to SRII Opco to fund purchases of an equivalent number of our Class A common shares. As a result of these and other transactions, at December 31, 2019, we own approximately 47.75% of the limited partner interests in SRII Opco.
Pursuant to the Contribution Agreements, until February 2025, the Contributors were entitled to receive additional SRII Opco Common Units as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of our Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
|
| | | | |
20-Day VWAP | | Earn-Out Consideration Payable to
AM Contributor | | Earn-Out Consideration Payable to
KFM Holdco, LLC |
$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 | | — |
The Contributors were entitled to the earn-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 exceeds the above-specified 20-Day VWAP hurdles. The expected sale of substantially all of our assets by mid-April 2020 will not trigger any earn-out consideration.
We also contributed $560.0 million in cash to Alta Mesa at the closing of the Business Combination.
Purchase Price for Alta Mesa
|
| | | | |
| (in thousands) | | February 9, 2018 |
Purchase Consideration: (1) | | |
SRII Opco Common Units issued (2) | | $ | 1,261,249 |
|
Estimated fair value of contingent earn-out purchase consideration (3) | | 284,109 |
|
| Settlement of preexisting working capital | | 5,476 |
|
| Total purchase price consideration | | $ | 1,550,834 |
|
_________________
| |
(1) | The purchase price consideration was for 100% of the limited partner interests in Alta Mesa and 100% of the economic interests and 90% of the voting interests in Alta Mesa GP. |
| |
(2) | At closing, the Riverstone Contributor received 20,000,000 SRII Opco Common Units and High Mesa received 138,402,398 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, High Mesa received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. |
| |
(3) | For a period of seven years following Closing, High Mesa was to be entitled to receive earn-out consideration in the form of SRII Opco Common Units. We determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent earn-out was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining term of the earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life. |
Purchase Price for KFM
|
| | | | |
| (in thousands) | | February 9, 2018 |
| Purchase Consideration: | | |
Cash (1) | | $ | 809,812 |
|
SRII Opco Common Units issued (2) | | 433,931 |
|
Estimated fair value of contingent earn-out purchase consideration (3) | | 88,105 |
|
| Settlement of preexisting working capital | | (5,476 | ) |
| Total purchase price consideration | | $ | 1,326,372 |
|
_________________
| |
(1) | The cash consideration paid at February 9, 2018 was net of estimated net working capital adjustments, transaction expenses, capital expenditures and banking fees. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back to the Company $5.0 million in cash. |
| |
(2) | At closing, KFM Holdco, LLC received 55,000,000 SRII Opco Common Units. Pursuant to a final closing statement during the second quarter of 2018, KFM Holdco remitted back 89,680 SRII Opco Common Units and an equivalent number of shares of our Class C Common Stock. The SRII Common Units were valued at approximately $7.90 per unit, reflecting discounts for holding requirements and liquidity. |
| |
(3) | The KFM earn-out consideration was recognized at fair value and has been classified in stockholders’ equity. The fair value of the earn-out was determined using the Monte Carlo simulation valuation method based on Level 3 inputs. The key inputs included the quoted market price for the Company’s Class A Common Stock, market volatility of a peer group of companies similar to the Company (due to the lack of trading activity in the Company’s Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining term of the earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps. |
Acquisition of acreage
In October 2018, we completed a transaction to acquire certain unproved oil and gas properties for $22.3 million, net of customary post-closing purchase price adjustments. The acquisition was funded utilizing borrowings under the Alta Mesa
RBL.
NOTE 10—PROPERTY AND EQUIPMENT
|
| | | | | | | |
| (in thousands) | December 31, 2019 | | December 31,
2018 |
| Oil and gas properties | | | |
| Unproved properties | $ | 813,310 |
| | $ | 816,282 |
|
| Accumulated impairment of unproved properties | (813,310 | ) | | (742,065 | ) |
| Unproved properties, net | — |
| | 74,217 |
|
| Proved oil and gas properties | 2,239,444 |
| | 2,110,346 |
|
| Accumulated depreciation, depletion, amortization and impairment | (2,024,092 | ) | | (1,421,226 | ) |
| Proved oil and gas properties, net | 215,352 |
| | 689,120 |
|
| Total oil and gas properties, net | 215,352 |
|
| 763,337 |
|
| Other property and equipment | | | |
| Land | 5,690 |
| | 5,600 |
|
| Fresh water wells | 27,373 |
| | 27,366 |
|
| Produced water disposal system | 108,966 |
| | 104,498 |
|
| Gas processing plant and gathering lines | 414,615 |
| | 380,470 |
|
| Office furniture, equipment and vehicles | 3,397 |
| | 3,703 |
|
| Accumulated depreciation and impairment | (453,013 | ) | | (77,368 | ) |
| Other property and equipment, net | 107,028 |
| | 444,269 |
|
| Total property and equipment, net | $ | 322,380 |
|
| $ | 1,207,606 |
|
Depreciation and Depletion
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Oil and gas properties depletion | $ | 118,003 |
| | $ | 129,579 |
| | | $ | 11,021 |
|
| Midstream tangible asset depreciation | 11,663 |
| | 8,235 |
| | | — |
|
| Other property and equipment depreciation | 1,646 |
| | 3,236 |
| | | 609 |
|
| Total depletion and depreciation | $ | 131,312 |
| | $ | 141,050 |
| | | $ | 11,630 |
|
Sale of Produced Water Assets
In November 2018, Alta Mesa sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines and 20 disposal wells, surface leases, easements and other agreements, to a subsidiary of KFM for approximately $99 million, including approximately $90 million in cash at closing and $9 million of purchase price adjustments which, in total, approximated the net book value of the produced water assets. This transaction was accounted for as a transfer of assets among entities under common control and recorded at carrying value. Accordingly, no gain or loss was recognized. In conjunction with the sale, Alta Mesa entered into a new fifteen-year produced water disposal agreement with KFM.
NOTE 11 — DISCONTINUED OPERATIONS (Predecessor)
Alta Mesa distributed its remaining non-STACK oil and gas assets and liabilities to High Mesa just prior to the closing of the Business Combination. We have determined that these non-STACK oil and gas assets and liabilities are discontinued operations during the Predecessor Periods and we have segregated their financial information in the financial statements.
Prior to the Business Combination, Alta Mesa had notes payable to its founder (“Founder Notes”) that bore simple interest at 10%. The Founder Notes were part of the non-STACK distribution. The balance of the Founder Notes at the time of conversion
was approximately $28.3 million, including accrued interest. Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period.
|
| | | |
| (in thousands) | January 1, 2018
Through
February 8, 2018 |
| Revenue: | |
| Oil | $ | 1,617 |
|
| Natural gas | 1,023 |
|
| Natural gas liquids | 236 |
|
| Other | 16 |
|
| Operating revenue | 2,892 |
|
| Loss on sale of assets | (1,923 | ) |
| Total revenue | 969 |
|
| Operating expenses: | |
| Lease operating | 1,770 |
|
| Transportation and marketing | 83 |
|
| Production taxes | 167 |
|
| Workovers | 127 |
|
| Depreciation, depletion and amortization | 884 |
|
| Impairment of assets | 5,560 |
|
| General and administrative | 21 |
|
| Total operating expenses | 8,612 |
|
| Other income (expense) | |
| Interest expense | (103 | ) |
| Total other expense | (103 | ) |
| Loss from discontinued operations, net of state income taxes | $ | (7,746 | ) |
|
| | | |
| (in thousands) | January 1, 2018
Through
February 8, 2018 |
| Total operating cash flows of discontinued operations | $ | 2,974 |
|
| Total investing cash flows of discontinued operations | (601 | ) |
NOTE 12—FAIR VALUE MEASUREMENTS
Recurring measurements
We historically utilized the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and gas derivatives. Inputs to these models included observable inputs from the NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and gas prices. We have classified the inputs used to determine fair values of all our oil, gas and natural gas liquids derivative contracts as Level 2. See Note 13 - Derivatives for further information.
Non-recurring measurements
We estimated the fair value of Alta Mesa’s 2024 Notes to be $45.3 million at December 31, 2019 ($312.5 million at December 31, 2018), based on their most recent trading values at or near each reporting date, which is a Level 1 determination.
At December 31, 2019, our oil, gas and midstream properties were evaluated for impairment based on the winning bid prices in a January 2020 auction of our assets conducted as part of a Bankruptcy Court approved sales process. These bid prices are considered a Level 1 input. Prior to December 31, 2019, our oil, gas, and midstream properties, as well as our goodwill and intangible assets in our Midstream segment were subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| (in thousands) | Carrying Value Before Assessment | | Estimated Fair Value | | Impairment | | Carrying Value Before Assessment | | Estimated Fair Value | | Impairment |
| Unproved oil and gas properties | $ | 31,023 |
| | $ | — |
| | $ | 31,023 |
| | $ | 816,282 |
| | $ | 74,217 |
| | $ | 742,065 |
|
| Proved oil and gas properties | 700,182 |
| | 215,352 |
| | 484,830 |
| | 1,895,670 |
| | 604,023 |
| | 1,291,647 |
|
| Operating lease right-of-use assets | 13,514 |
| | — |
| | 13,514 |
| | — |
| | — |
| | — |
|
Other long-term assets(1) | 51,518 |
| | 24,189 |
| | 27,329 |
| | — |
| | — |
| | — |
|
| Equity method investment | — |
| | — |
| | — |
| | 17,063 |
| | 1,100 |
| | 15,963 |
|
Midstream property and equipment(1) | 432,415 |
| | 83,818 |
| | 348,597 |
| | 474,529 |
| | 406,122 |
| | 68,407 |
|
| Intangible assets | — |
| | — |
| | — |
| | 394,999 |
| | — |
| | 394,999 |
|
| Goodwill | — |
| | — |
| | — |
| | 691,970 |
| | — |
| | 691,970 |
|
| Total | $ | 1,228,652 |
| | $ | 323,359 |
| | $ | 905,293 |
| | $ | 4,290,513 |
| | $ | 1,085,462 |
| | $ | 3,205,051 |
|
_________________
(1) Amounts reflect only those assets that were impaired.
We estimate the fair value of additions to asset retirement obligations associated with new or acquired properties. Such estimations of fair value are based on present value techniques that utilize company-specific information for inputs such as the cost and timing of plugging and abandonment of wells and facilities. These inputs are classified as Level 3.
NOTE 13—DERIVATIVES
In connection with Alta Mesa’s bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts in September 2019 for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. After September 2019, we held no open derivative positions.
The following summarizes the fair value and classification of our derivatives at December 31, 2018:
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of assets | | Gross liabilities offset against assets in the Balance Sheet | | Net fair value of assets presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current assets | | $ | 22,512 |
| | $ | (6,089 | ) | | $ | 16,423 |
|
| Derivatives, long-term assets | | 7,910 |
| | (4,963 | ) | | 2,947 |
|
| Total | | $ | 30,422 |
| | $ | (11,052 | ) | | $ | 19,370 |
|
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of liabilities | | Gross assets offset against liabilities in the Balance Sheet | | Net fair value of liabilities presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current liabilities | | $ | 7,799 |
| | $ | (6,089 | ) | | $ | 1,710 |
|
| Derivatives, long-term liabilities | | 5,143 |
| | (4,963 | ) | | 180 |
|
| Total | | $ | 12,942 |
| | $ | (11,052 | ) | | $ | 1,890 |
|
The following summarizes the effect of our derivatives in our statements of operations (in thousands):
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | | February 9, 2018 | | | January 1, 2018 |
| Derivatives not | Year Ended | | Through | | | Through |
| designated as hedges | December 31, 2019 | | December 31, 2018 | | | February 8, 2018 |
| Gain (loss) on derivatives - | | | | | | |
| Oil commodity contracts | $ | (16,013 | ) | | $ | (3,559 | ) | | | $ | 4,796 |
|
| Natural gas commodity contracts | 4,269 |
| | (6,688 | ) | | | 1,867 |
|
| Total gain (loss) on derivatives | $ | (11,744 | ) | | $ | (10,247 | ) | | | $ | 6,663 |
|
Other receivables at December 31, 2018 included $1.3 million of derivative positions that were settled in January 2019.
NOTE 14 — INTANGIBLE ASSETS
Our intangible assets represented customer relationships within theMidstream segment acquired in the Business Combination.
|
| | | |
| (in thousands) | December 31, 2018 |
| Customer contracts and relationships acquired | $ | 414,150 |
|
| Accumulated amortization and impairment | (414,150 | ) |
| Intangibles, net | $ | — |
|
Amortization expense was $19.2 million during the 2018 Successor Period.
NOTE 15 — EQUITY METHOD INVESTMENT
In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party. During 2018, we invested $17.1 million in Cimarron, but at December 31, 2018, based on our decision to ultimately abandon the project, we reduced our investment to fair value, which we determined was our portion of the estimated cash remaining at Cimarron after satisfaction of liabilities.
In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. As a result, we adjusted our preacquisition equity method investment to the fair value of the residual assets remaining in Cimarron, consisting primarily of cash. This resulted in our recognition of a gain of $5.5 million, which is included in “Equity in earnings of unconsolidated subsidiaries” in our consolidated statements of operations. Following this transaction, Cimarron became our wholly owned subsidiary.
Activity in our equity method investment was as follows:
|
| | | |
| (in thousands) | |
| Balance, as of February 9, 2018 | $ | — |
|
| Capital contributions | 17,063 |
|
| Impairment | (15,963 | ) |
| Balance, as of December 31, 2018 | 1,100 |
|
| Equity in earnings through November 13, 2019 | 713 |
|
| Adjustment of investment in Cimarron to fair value based on assets received | 5,503 |
|
| Ending balance before obtaining control | $ | 7,316 |
|
We obtained control of the following remaining assets and assumed the following liabilities of Cimarron as a result of execution of an agreement between Cimarron and our partner in November 2019:
|
| | | |
| (in thousands) | |
| Cash | $ | 7,238 |
|
| Land and rights-of-way | 90 |
|
| Accrued liabilities | (12 | ) |
| Net assets received upon consolidation of Cimarron | $ | 7,316 |
|
NOTE 16 — ASSET RETIREMENT OBLIGATIONS
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018 Through December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Balance, beginning of period | $ | 11,552 |
| | $ | — |
| | | $ | 10,469 |
|
Liabilities assumed in Business Combination(1) | — |
| | 5,998 |
| | | — |
|
| Liabilities incurred | 859 |
| | 2,676 |
| | | — |
|
| Liabilities settled | (234 | ) | | (1,610 | ) | | | (63 | ) |
| Liabilities transferred in sale of properties | — |
| | (19 | ) | | | — |
|
| Revisions to estimates | 26 |
| | 3,766 |
| | | 63 |
|
| Accretion expense | 980 |
| | 741 |
| | | 40 |
|
| Balance, end of period | 13,183 |
| | 11,552 |
| | | 10,509 |
|
| Less: current portion | 34 |
| | 2,079 |
| | | 33 |
|
| Long-term portion | $ | 13,149 |
| | $ | 9,473 |
| | | $ | 10,476 |
|
_________________
| |
(1) | Represents the same wells as under the Predecessor Period but valued at a higher interest rate of 10.2% compared to Predecessor interest rates ranging between 4.4% and 8.8%. |
NOTE 17 — LONG-TERM DEBT, NET
|
| | | | | | | | |
| (in thousands) | December 31, 2019 | | | December 31, 2018 |
| Alta Mesa RBL | $ | 355,943 |
| | | $ | 161,000 |
|
| KFM Credit Facility | 224,000 |
| | | 174,000 |
|
| 2024 Notes | 500,000 |
| | | 500,000 |
|
| Unamortized premium on 2024 notes | — |
| | | 29,123 |
|
| Total debt, net | 1,079,943 |
| | | 864,123 |
|
| Less: Liabilities subject to compromise | (855,943 | ) | | | — |
|
| Less: Current portion | (224,000 | ) | | | (690,123 | ) |
| Long-term debt, net | $ | — |
| | | $ | 174,000 |
|
Alta Mesa RBL
In connection with the Business Combination, we entered into the Alta Mesa RBL which has a face amount of $1.0 billion and had an initial $350.0 million borrowing base, which was subsequently increased to $400.0 million in April 2018. The facility matures in February 2023 and was subject to semiannual redeterminations, as well as an additional optional redetermination between semiannual redeterminations either by us or the lender group. As of December 31, 2019, we had $355.9 million in outstanding borrowings under the Alta Mesa RBL, plus $1.9 million in outstanding letters of credit.
Amounts outstanding under the Alta Mesa RBL are secured by first priority liens on substantially all of our upstream oil and gas properties and all of our equity of our wholly owned guarantor subsidiaries. Upon closing of the expected AMH Sale Transaction, these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly
owned guarantor subsidiaries. Additionally, SRII Opco and Alta Mesa GP, both of which are under bankruptcy protection at the time of this filing, had pledged their respective partner interests as security.
In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, a reduction from the prior $370.0 million established in April 2019. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default.
Prior to default, we had the ability to designate borrowings in either Eurodollars or at a reference rate. Subsequent to our default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%. At December 31, 2019, outstanding borrowings bore interest at a rate of 10.75%, which consisted of the Prime Rate plus additional penalty margins of 2.00% due to our borrowing base deficiency and 2.00% due to our default.
Prior to our default, restrictive covenants generally limited our ability to incur additional indebtedness, sell assets, guarantee or make loans to others, make investments, enter into mergers, make certain payments and distributions in excess of specific amounts, enter into or be party to hedge agreements outside of hedge requirements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Subsequent to the AMH Debtors’ bankruptcy filing, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.
The Alta Mesa RBL had two covenants that no longer require quarterly testing as a result of our bankruptcy filing.
KFM Credit Facility
Effective May 30, 2018, KFM entered into the KFM Credit Facility with an aggregate committed amount of $300.0 million. The KFM Credit Facility matures in May 2023. As of December 31, 2019, outstanding borrowings totaled $224.0 million and there were no outstanding letters of credit.
Amounts outstanding under the KFM Credit Facility are secured by first priority liens on substantially all of KFM’s assets and are guaranteed by KFM’s wholly owned subsidiaries. Upon closing of the expected KFM Sale Transaction these outstanding amounts will be secured by the proceeds from such sale and all of the equity of our wholly owned guarantor subsidiaries. Additionally, SRII Opco, LP had pledged its membership interests in KFM as collateral.
In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility alleged a potential event of default in respect of liens placed on KFM’s assets. As a result, KFM was unable to borrow additional funds under the KFM Credit Facility after September 2019.
On January 12, 2020, the KFM Debtors filed for protection under the Bankruptcy Code. This filing constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder.
Prior to the alleged default, we had the ability to designate borrowings under the KFM Credit Facility in either Eurodollars or at a reference rate. Subsequent to the alleged default, all Eurodollar loans were converted into reference rate loans at maturity, which bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus an applicable margin ranging from 1.00% to 2.25%. At December 31, 2019, outstanding borrowings bore interest at a rate of 6.5%.
Prior to our default, restrictive covenants limited our ability to incur additional indebtedness, dispose of assets, make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge
agreements, amend organizational documents, incur liens, hold cash in excess of $15.0 million and engage in certain other transactions. Subsequent to the KFM Debtors bankruptcy filing in January 2020, we currently operate under cash collateral orders issued by the Bankruptcy Court that allow us to use our cash collateral, with restrictions on our ability to dispose of assets or settle liabilities. The terms and conditions of the cash collateral orders include, without limitation, adherence to a budget with an agreed upon variance and provide for certain monthly reporting obligations.
The KFM Credit Facility also had two maintenance covenants that no longer require quarterly testing as a result of the cash collateral orders issued in January 2020.
2024 Notes
Our 2024 Notes have a face value of$500 million and bear interest at 7.875% per annum, payable semi-annually each June 15 and December 15. The 2024 Notes mature in December 2024.
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.
The 2024 Notes are guaranteed by each of Alta Mesa’s subsidiaries and rank equal in right of payment to all of Alta Mesa’s existing senior indebtedness; senior in right of payment to all of Alta Mesa’s existing and future subordinated indebtedness; effectively subordinated to all of Alta Mesa’s existing secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa RBL; 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 terms of the 2024 Notes originally provided for early redemption over certain periods at their principal amount plus an applicable make-whole premium and contained covenants restricting our ability to enter into certain transactions or to sell or otherwise dispose of assets, among other things.
Bond Premium
The fair value of the 2024 Notes as of the Business Combination was $533.6 million, yielding a bond premium of $33.6 million. Amortization of the premium reduced our interest expense by $3.4 million and $4.5 million during the year ended December 31, 2019 and the 2018 Successor Period, respectively. Upon filing for bankruptcy protection, the remaining unamortized premium was written off as part of reorganization items, net.
Scheduled Maturities of Debt
|
| | | | |
| Fiscal Year | | (in thousands) |
| 2023 | | $ | 579,943 |
|
| 2024 | | 500,000 |
|
| | | $ | 1,079,943 |
|
Based on the defaults associated with Alta Mesa’s and KFM’s bankruptcy filings and the reporting requirements for entities under bankruptcy protection, we have classified all of the indebtedness under the Alta Mesa RBL as liabilities subject to compromise and all of the indebtedness under the KFM Credit Facility as current liabilities at December 31, 2019 despite the scheduled maturities shown above. At December 31, 2018, all of the indebtedness under the Alta Mesa RBL and the related bond premium were classified as current liabilities due to our expectations at that time the indebtedness would become accelerated during 2019.
NOTE 18 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
|
| | | | | | | | |
| | Successor |
| (in thousands) | December 31,
2019 | | | December 31,
2018 |
| Accounts payable | $ | 27,349 |
| | | $ | 20,422 |
|
| | | | | |
| Accruals for capital expenditures | 1,244 |
| | | 139,904 |
|
| Revenue and royalties payable | 27,355 |
| | | 50,241 |
|
| Accruals for operating expenses | 25,131 |
| | | 21,830 |
|
| Accrued interest | 9,663 |
| | | 2,477 |
|
| Derivative settlements | 511 |
| | | 109 |
|
| Other | 1,716 |
| | | 12,456 |
|
| Total accrued liabilities | 65,620 |
| | | 227,017 |
|
| Less: liabilities subject to compromise | (28,832 | ) | | | — |
|
| Accounts payable and accrued liabilities | $ | 64,137 |
| | | $ | 247,439 |
|
NOTE 19 — COMMITMENTS AND CONTINGENCIES
Commitments
Firm Natural Gas Transportation Commitments
We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of natural gas that extend through 2036 with the following remaining minimum commitments at December 31, 2019:
|
| | | | | | | | | | | | |
| (in thousands) | | Upstream | | Midstream(1) | | Total |
| 2020 | | $ | 12,236 |
| | $ | 6,116 |
| | $ | 18,352 |
|
| 2021 | | 12,236 |
| | 6,116 |
| | 18,352 |
|
| 2022 | | 12,236 |
| | 5,859 |
| | 18,095 |
|
| 2023 | | 12,236 |
| | 5,676 |
| | 17,912 |
|
| 2024 | | 5,666 |
| | 5,676 |
| | 11,342 |
|
| Thereafter | | 19,358 |
| | 64,328 |
| | 83,686 |
|
| | | $ | 73,968 |
| | $ | 93,771 |
| | $ | 167,739 |
|
_________________
| |
(1) | Total cash payments required for committed capacity in MMBtus of 45,750,000 in 2020, 45,625,000 in 2021, 40,275,000 in 2022, 36,500,000 in 2023, 36,600,000 in 2024 and 413,850,000 thereafter. KFM does not currently utilize the full amount of contracted capacity but strives to release capacity to third parties to attempt to minimize the under-utilization. |
Other Commitments
KFM has entered into 2 commitments with other midstream providers with the following significant terms:
An annual commitment for 3,650,000 mcf of processing volumes that runs through December 31, 2021. KFM is required to pay $0.85 per mcf for any shortfall volumes. Volumes processed under this contract are sold to the processor at market value after processing. KFM has entered into an agreement with Alta Mesa whereby Alta Mesa will reimburse KFM for half of the expenses associated with any shortfall.
A commitment for approximately $128,000 per month of processing services that runs through December 31, 2021. Although there are no associated volumetric minimums, KFM is required to pay for the value of any shortfall from the approximately $128,000 monthly fee. Any volumes processed under this contract are sold to the processor at prevailing market prices after processing.
Pursuant to the expected Sale Transactions, we anticipate certain of these firm and other commitments will be assumed by the Buyer. As part of the Chapter 11 proceedings any remaining commitments will be rejected by the Bankruptcy Court.
Contingencies
Environmental claims
Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries 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 its oil and 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 as of December 31, 2019.
Litigation
On January 30, 2019, the Company, James T. Hackett, our then interim Chief Executive Officer and Chairman of the Board, certain of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. The District Court transferred this action to the U.S. District Court for the Southern District of Texas.
On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle, our former President and Chief Executive Officer, and Michael A. McCabe, our former Chief Financial Officer. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.
On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.
The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.
Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.
In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”, a subsidiary of HMI), Alta Mesa, and other defendants. Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company.
SEC Investigation
The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.
Other contingencies
We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters.
Performance appreciation rights.
Our Predecessor had a plan that was intended to provide incentive compensation to key employees and consultants. We canceled all amounts due under the plan at the time of the Business Combination, but recognized and paid $10.9 million as strategic costs in G&A during the 2018 Successor Period.
NOTE 20 — EMPLOYEE BENEFIT PLANS
We sponsor a 401(k) savings plan, whereby the employees can elect to make contributions. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions typically vested 50% after two years and become fully vested after three years. Company matching contributions were approximately $1.2 million, $1.1 million, and $0.3 million for 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively.
Due to the extent of our employee reductions and the expected Sale Transactions, we expect that all employees will receive accelerated vesting of company matching contributions as a result of a partial plan termination.
NOTE 21 — SIGNIFICANT CONCENTRATIONS
During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed our oil, gas and NGLs for a marketing fee that was deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. In June 2019, we terminated our oil and NGL marketing agreement with ARM and began marketing such products internally.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Revenue marketed by ARM on our behalf | $ | 123,000 |
| | $ | 336,248 |
| | | $ | 28,757 |
|
| | | | | | | |
| Marketing and management fees paid to ARM | $ | 1,715 |
| | $ | — |
| | | $ | — |
|
| Fees paid to ARM for services relating to our derivatives | 496 |
| | 784 |
| | | 66 |
|
| Total fees paid to ARM | $ | 2,211 |
| | $ | 784 |
| | | $ | 66 |
|
Receivables from ARM for sales on our behalf were $6.8 million and $43.8 million as of December 31, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.
For the year ended December 31, 2019, one customer accounted for 40.5% of our total operating revenue for the period.
We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available.
NOTE 22 — STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
Class A Common Stock
Holders of our Class A Common Stock are entitled to 1 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 constitute a single class for all stockholder votes. 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 5 directors in total).
In the event of our liquidation or dissolution, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining 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.
In August 2018, the Board of Directors authorized up to $50.0 million for the repurchase of our outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Repurchases could be made at the Company’s discretion in open market or private transactions. During 2018, we repurchased and retired 3,101,510 shares of Class A Common Stock, which remain authorized and are available for reissuance at a future date. The price paid for the shares repurchased, including commissions, that was in excess of par value has been recorded as a reduction of approximately $14.8 million in additional paid in capital.To fund the repurchase of our Class A shares of Common Stock, the Company sold 3,101,510 of its SRII Opco Common Units to SRII Opco for the same price paid to the market for the Class A shares repurchased. This resulted in an increase during the 2018 Successor Period in the ownership position of the noncontrolling interest holders in SRII Opco, and an offsetting reduction in the Company’s additional paid in capital, totaling approximately $10.8 million.
In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our Class A Common Stock under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
Class C Common Stock
In connection with the Business Combination, we issued 213,402,398 shares of Class C Common Stock to the Contributors, 199,987,976 of which remain outstanding at December 31, 2019 (202,169,576 at December 31, 2018).
Holders of Class C Common Stock, voting as a separate class, are entitled to approve any amendment of our certificate of incorporation that would alter or change the rights and powers of the Class C Common Stock. Holders of Class C Common Stock are not entitled to any dividends and are not entitled to receive any of our assets in the event of our liquidation or dissolution.
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 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 canceled. During 2019, we issued 2,181,600 shares of our Class A Common Stock to an owner of SRII Opco Common Units in exchange for those units, and canceled 2,181,600 of our Class C Common Stock. During the 2018 Successor Period, we issued 2,752,312 and 9,588,764 shares of our Class A Common Stock to equity owners of High Mesa and KFM Holdco, LLC, respectively, and canceled 12,341,076 shares of our Class C Common Stock as a result of the direct exchange of SRII Opco Common Units redemption.
Redeemable Series A Preferred Stock
As of December 31, 2019, Bayou City Energy Management LLC (“Bayou City”) and HPS Investment Partners, LLC (“HPS”) each own 1 of the 2 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. AM Equity Holding, LP elected to redeem their one share for par value in December 2018. 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 dividends. The Series A Preferred Stock is not convertible into any other of our securities, but will be redeemable by us for par value 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. If the Series A Preferred Stock remains outstanding, its holders are entitled to nominate and elect up to 2 directors to our board of directors for a period of up to five years following the closing of the Business Combination based on their and their affiliates’ beneficial ownership of common stock.
Redeemable Series BPreferred Stock
As of December 31, 2019, 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 limited partnership agreement of SRII Opco). 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 dividends. The Series B Preferred Stock is not convertible into any other security of the Company, but will be redeemable by us for par value 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. If the Series B Preferred Stock remains outstanding, its holder is entitled to nominate and elect up to 3 directors to our board of directors for a period of up to five years following the closing of the Business Combination based on its and its affiliates’ beneficial ownership of common stock.
Warrants
As of December 31, 2019, we had 62,966,651 warrants outstanding, consisting of 34,499,985 public warrants originally sold in our IPO (“Public Warrants”), 15,133,333 Private Placement Warrants sold to our Sponsor and 13,333,333 Forward Purchase Warrants issued to Riverstone VI SR II Holdings, LP.
Each Public Warrant entitles the holder to purchase 1 share of our Class A Common Stock for $11.50 and expire in February 2023.
The Private Placement Warrants are identical to the Public Warrants, except the Private Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.
The Forward Purchase Warrants have terms and provisions that are identical to those of the Private Placement Warrants, except the Forward Purchase Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. The Forward Purchase Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor.
In February 2020, we filed a Form 15 with the Securities and Exchange Commission to deregister our warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
Noncontrolling Interest (“NCI”)
NCI relates to SRII Opco Common Units that were originally issued to the Contributors, in connection with the Business Combination and continue to be held by holders other than the Company. At the date of the Business Combination, the noncontrolling interest owners held 55.8% of the limited partner interests in SRII Opco. The non-controlling interest percentage is affected by Class C Common Stock conversions and the Class A Common Stock activities after which, the noncontrolling interest owners held 52.25% at December 31, 2019 (53.0% at December 31, 2018).
Partnership Management and Control
Alta Mesa’samended and restatedpartnership agreement provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by Alta Mesa GP referred to as “GP Units”. Alta Mesa GP owns all the GP Units and SRII Opco owns all the LP Units.
Since Alta Mesa is a limited partnership, its operations and activities are managed by the board of directors of its general partner, Alta Mesa GP. The limited liability company agreement of Alta Mesa GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic rights in Alta Mesa GP and (ii) Class B Units, which hold 100% of the voting interests in Alta Mesa GP.
SRII Opco is the sole owner of Alta Mesa GP’s Class A Units and owns 90% of the Class B Units. Our former President and Chief Executive Officer and our former Chief Operating Officer—Upstream, along with certain affiliates of Bayou City and HPS, own an aggregate 10% of the Class B Units. Alta Mesa GP’s board of directors are selected by the Class B members. Notwithstanding the foregoing, voting control of Alta Mesa GP is vested in SRII Opco pursuant to a voting agreement.
Cancellation
We expect that our reorganization pursuant to the bankruptcy proceedings will result in the cancellation of all equity that existed at December 31, 2019.
NOTE 23 — EQUITY-BASED COMPENSATION (Successor)
We have adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of 50,000,000 shares of Class A Common Stock were initially reserved for issuance under the LTIP. The LTIP provided for the grant of stock awards, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units and other awards in our Class A Common Stock. Prior to the Business Combination, we had no equity-based compensation programs. During 2019 and the 2018 Successor Period, we recognized stock-based compensation expense of $6.4 million and $22.0 million, respectively, in general and administrative expense including accelerated vesting in 2018 for separated executives related to the LTIP.
On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the LTIP. Accordingly, we are no longer able to grant restricted stock or shares of our Class A Common Stock in satisfaction of our outstanding unexercised stock options, unvested restricted stock and unvested performance-based restricted stock units (“PSUs”) and we anticipate those outstanding stock awards will be canceled as a result of our bankruptcy filing.
Stock options
Stock options previously granted were set to expire seven years from the grant date and generally were to vest in one-third increments each year, based on continued employment. Employees had 90 days after termination to exercise vested stock options, unless extended by an employment agreement.
|
| | | | | | | | | | | | | | | | | | |
| | | Stock Options | | Weighted Average Exercise Price | | Weighted Average Grant-Date Fair Value | | Weighted Average Remaining Term (in years) | | Aggregate Intrinsic Value (in thousands) |
| Outstanding as of February 9, 2018 | | — |
| | $ | — |
| | $ | — |
| | — |
| | $ | — |
|
| Granted | | 5,283,224 |
| | 8.80 |
| | 4.33 |
| | — |
| | — |
|
| Exercised | | — |
| | — |
| | — |
| | — |
| | — |
|
| Forfeited or expired | | (139,319 | ) | | 9.38 |
| | 4.55 |
| | — |
| | — |
|
| Outstanding as of December 31, 2018 | | 5,143,905 |
| | $ | 8.79 |
| | $ | 4.33 |
| | 5.3 |
| | $ | — |
|
| Granted | | 157,710 |
| | $ | 1.07 |
| | $ | 0.61 |
| | — |
| | $ | — |
|
| Exercised | | — |
| | — |
| | — |
| | — |
| | — |
|
| Forfeited or expired | | (1,498,328 | ) | | 8.44 |
| | 4.20 |
| | — |
| | — |
|
| Outstanding as of December 31, 2019 | | 3,803,287 |
| | $ | 4.80 |
| | $ | 4.22 |
| | 3.19 |
| | $ | — |
|
| Exercisable as of December 31, 2019 | | 2,260,388 |
| | $ | 9.21 |
| | $ | 4.49 |
| | 5.15 |
| | — |
|
The following assumptions were used to determine the fair value of our 2019 and 2018 option grants:
|
| | | | | |
| | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Expected term (in years) | 4.5 |
| | 4.5 |
|
| Expected stock volatility | 69.8 | % | | 64.6 | % |
| Dividend yield | — |
| | — |
|
| Risk-free interest rate | 2.4 | % | | 2.5 | % |
Unrecognized compensation cost related to non-vested stock options at December 31, 2019 was $3.5 million, with a remaining weighted average vesting period of 0.8 years.
Restricted stock
Restricted stock granted to employees generally vested in one-third increments each year based on continued employment. Prior to vesting, unvested restricted stock may not be traded but was entitled to accumulate any dividend value. During the 2018 Successor Period, we granted 98,199 shares to certain of our directors, all which vested immediately, and granted 2,140,160 restricted stock awards to employees. All 2019 grants were to employees.
The following table provides information about activity in our restricted stock awards during the 2018 Successor Period and year ended December 31, 2019:
|
| | | | | | |
| | Restricted Stock Awards | | Weighted Average Grant Date Fair Value per share |
| Outstanding as of February 9, 2018 | — |
| | $ | — |
|
| Granted | 2,238,359 |
| | 7.54 |
|
Vested(1) | (384,413 | ) | | 8.40 |
|
| Forfeited or expired | (61,935 | ) | | 8.80 |
|
| Outstanding as of December 31, 2018 | 1,792,011 |
| | 7.32 |
|
| Granted | 70,093 |
| | 0.96 |
|
Vested(1) | (619,061 | ) | | 7.04 |
|
| Forfeited or expired | (719,766 | ) | | 7.36 |
|
| Outstanding as of December 31, 2019 | 523,277 |
| | $ | 6.74 |
|
_________________
(1) To satisfy minimum tax withholding, 130,432 and 94,576 shares were withheld in 2019 and during the 2018 Successor Period.
Unrecognized compensation cost related to unvested restricted shares at December 31, 2019 was $2.1 million, with a remaining weighted average vesting period of 1.4 years.
Restricted stock units
Our PSUs granted in 2018 generally vested over three years at 20% during the first year, 30% during the second year and 50% was schedule to vest during the third year. The number of PSUs vesting each year were based on the achievement of annual performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest could range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the 2018 Successor Period only the performance goals and objectives for 2018 had been established as of December 31, 2018. Those 2018 performance goals were not attained, and the 2018 award tranche was forfeited, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. The targets for 2019 were established in March 2019. The 2019 award tranche vested at 199% of target. Due to our bankruptcy and the expected sale of substantially all of our assets, no performance targets will be established for the 2020 award tranche and we expect that tranche will be forfeited as part of our bankruptcy proceedings.
The following table provides information about activity in our PSUs granted during the 2018 Successor Period and year ended December 31, 2019:
|
| | | | | | |
| | PSUs | | Weighted Average Grant Date Fair Value per unit |
| Outstanding as of February 9, 2018 | — |
| | $ | — |
|
| Granted | 2,093,453 |
| | 4.07 |
|
Vested (1) | (1,559,749 | ) | | 2.53 |
|
| Forfeited or expired | (533,704 | ) | | 8.54 |
|
| Outstanding as of December 31, 2018 | — |
| | — |
|
| Granted | 1,220,490 |
| | 0.32 |
|
| Vested | (100,870 | ) | | 0.96 |
|
| Forfeited or expired | (54,112 | ) | | 0.27 |
|
| Outstanding as of December 31, 2019 | 1,065,508 |
| | $ | 0.27 |
|
_________________
(1) To satisfy minimum tax withholding, 32,481 and 388,655 shares were withheld in 2019 and during the 2018 Successor Period.
As of December 31, 2019, there was 0 unrecognized compensation cost related to unvested PSUs.
NOTE 24 — INCOME TAXES
As a result of the Business Combination, our wholly owned subsidiary, SRII Opco GP, is the general partner of SRII Opco, which became the sole managing member of Alta Mesa GP and KFM, and as a result, we began consolidating the financial results of Alta Mesa and KFM. SRII Opco is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, SRII Opco is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by SRII Opco is passed through to and included in the taxable income or loss of its limited partners, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of SRII Opco, as well as any stand-alone income or loss generated by the Company.
Income tax expense (benefit) included in the statements of operations is detailed below:
|
| | | | | | | |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Current taxes: | | | |
| Federal | $ | — |
| | $ | (69 | ) |
| State | — |
| | — |
|
| | — |
| | (69 | ) |
| Deferred taxes: | | | |
| Federal | — |
| | — |
|
| State | — |
| | — |
|
| | — |
| | — |
|
| Income tax expense (benefit) | $ | — |
| | $ | (69 | ) |
A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations is as follows:
|
| | | | | | | | | | | | | |
| (Amounts in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 |
| Federal income tax expense (benefit) - at statutory rate | $ | (195,221 | ) | | 21.00 | % | | $ | (682,378 | ) | | 21.00% |
| State income taxes - net of federal income tax benefit | (44,064 | ) | | 4.74 |
| | (154,022 | ) | | 4.74 |
|
| Non-controlling interest | 123,316 |
| | (13.27 | ) | | 833,239 |
| | (25.64 | ) |
| Return to provision | (1,690 | ) | | 0.18 |
| | (71 | ) | | — |
|
| Change in valuation allowance | 136,568 |
| | (14.69 | ) | | 3,135 |
| | (0.1 | ) |
| Permanent items | — |
| | — |
| | 25 |
| | — |
|
| Other | (18,909 | ) | | 2.04 |
| | 3 |
| | — |
|
| Income tax expense (benefit) | $ | — |
| | — | % | | $ | (69 | ) | | — | % |
The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:
|
| | | | | | | |
| (in thousands) | December 31, 2019 | | December 31, 2018 |
| Deferred tax asset: | | | |
| Investment in SRII Opco, LP | $ | 424,086 |
| | $ | 269,846 |
|
| 59(e) capitalized IDC | 53,814 |
| | — |
|
| NOL carryforward | 29,866 |
| | 101,337 |
|
| Organizational/startup costs | 144 |
| | 154 |
|
| Other | 7 |
| | 11 |
|
| Total deferred tax assets | 507,917 |
| | 371,348 |
|
| Less: valuation allowance | (507,917 | ) | | (371,348 | ) |
| Net deferred tax assets | — |
| | — |
|
| | | | |
| Deferred tax liability | — |
| | — |
|
| Total net deferred tax assets/(liabilities) | $ | — |
| | $ | — |
|
The change in our valuation allowance during the year ended December 31, 2019 was $136.6 million.
In connection with the Business Combination, we entered into the Tax Receivable Agreement with SRII Opco, High Mesa, and the Riverstone Contributor. This agreement generally provides for the payment by us of 85% of the amount of net cash savings, if any, in 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) tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock 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 obligations of the Company and not obligations of SRII Opco, and the payments required could have been 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 tax 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 continues 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.
As of December 31, 2019, there has been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash income tax savings multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, 2019 we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have recorded no liability for such at this time. We believe there is a very low likelihood that we will utilize these attributes in 2020 or future years, due to the expected outcome of our bankruptcy filing.
NOTE 25 — RELATED PARTY TRANSACTIONS
Gathering Agreements
On August 31, 2015, Alta Mesa’s wholly owned subsidiary, 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. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016, and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and
Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements.
Employees
David McClure, our former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $769,000, $1,158,000, and $29,000 for the year ended December 31, 2019, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.
Bayou City Joint Development Agreement
In January 2016, Oklahoma EnergyAcquisitions, LP, entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE,BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of ourits STACK acreage. The JDA established a development plan of 60 wells in three tranches and providedprovides opportunities for the parties to potentially agree todevelop an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. tranche. In exchange for fundingcarrying the drilling and completion costs, BCE receivedreceives 80% of our working interest in each wellbore, which BCE interest wouldwill be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return.return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE wouldwill each bear its respective proportionate working interest share of all subsequent operating costs and expenses related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, dependeddepends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA, a portion of which was refunded during the 2018 Successor Period. As of December 31, 2019, 61 joint
wells have been drilled or spudded. As of December 31, 2019 and December 31, 2018, $3.2 million and $9.8 million, respectively of revenue payable liabilities and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. No new wells were drilled in 2019 under the JDA and as of December 31, 2019, there were no funded horizontal wells in progress, and none were developed in 2020. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves. The JDA expired in January 2020 pursuant toon its terms.
BCE-Mach III LLC
BCE-Mach III LLC, a Delaware limited liability company formed by Bayou City, Energy Management, LLC, a related party, and Mach Resources LLC, is the buyercurrently party to certain purchase and sale agreements to buy all of our assets pursuantassets.
Related Party Policy
Prior to the Sale Transactions, which we expect to close no later than mid-April 2020.
High Mesa - Promissory Notes
In September 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiaryclosing of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2019 and 2018, amounts due under the promissory note totaled $1.7 million. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, 2019 and 2018, the note receivable amounted to $11.7 million. HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2019, we have an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.
Interest income on the promissory notes amounted to approximately $0.9 million and $0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.
High Mesa - Management Services Agreement
In connection with the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the HMI Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the HMI Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.
Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (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 reimbursable pursuant to the HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement have reflected these costs as “Related party receivables” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million, respectively, for costs and expenses incurred on HMI’s behalf. During 2019, we billed HMI $0.8 million for incremental costs incurred and have received approximately $1.1 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable.
We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result, at December 31, 2019 and December 31, 2018, we had allowances for uncollectible accounts of $9.8 million and $9.0 million, respectively, to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.
NOTE 26 — BUSINESS SEGMENT INFORMATION
Following the Business Combination, we did not have 2 reportable segments: (i) Upstreama 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.
Upon closing of our Business Combination, we adopted a Related Person Transaction Policy, which addresses the reporting, review and (ii) Midstream. Each segment is ultimately ledapproval or ratification of transactions with related persons. In addition, we have adopted a Corporate Code of Business Conduct and Ethics requiring us to avoid, wherever possible, all conflicts of interests, except under guidelines or resolutions approved by our Chief Executive Officer, who is alsoBoard (or the Chief Operating Decision Maker (“CODM”). The CODM evaluates segment performance using Adjusted EBITDAX and Adjusted EBITDA.
We believe Adjusted EBITDAX and Adjusted EBITDA are useful because it allows users to more effectively evaluate our operating performance, compare the resultsappropriate committee of our operations from period to period and against our peers without regard to our financing methodsBoard) or capital structure and because it highlights trendsas disclosed in our businesspublic filings with the SEC. Under our Corporate Code of Business Conduct and 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 each of these policies is available at www.altamesa.net.
In addition, our Audit Committee, pursuant to its charter, is responsible for reviewing and approving related party transactions to the extent that may not otherwisewe 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 apparent when relying solelyrequired to approve a related party transaction. We also require each of our directors and executive officers to complete a 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 GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should notthe part of a director, employee or officer. Our Audit Committee will review on an annual basis any previously approved or ratified related party transactions.
NASDAQ listing rules require that a majority of the board of directors of a listed company be consideredcomposed of “independent directors,” which is defined generally as a person other than an alternative to net income (loss), operating income (loss)officer or employee of the company or its subsidiaries or any other performance measure derivedindividual having a relationship which, in accordancethe opinion of the company’s board of directors would interfere with GAAPthe director’s exercise of independent judgment in carrying out the responsibilities of a director. Although the Company is no longer listed on NASDAQ, the Company’s Board made a determination prior to delisting that Mses. Diana J. Walters and may not be comparable to similarly titled measures in other companies’ reports.
|
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2019 |
| (in thousands) | Exploration & Production | | Midstream | | Corporate and Eliminations | | Total |
| Revenue | | | | | | | |
| Oil | $ | 328,386 |
| | $ | — |
| | $ | — |
| | $ | 328,386 |
|
| Natural gas | 53,693 |
| | — |
| | — |
| | 53,693 |
|
| Natural gas liquids | 40,026 |
| | — |
| | — |
| | 40,026 |
|
| Sales of gathered production | — |
| | 37,195 |
| | — |
| | 37,195 |
|
| Midstream revenue | — |
| | 84,763 |
| | (54,173 | ) | | 30,590 |
|
| Segment sales revenue | 422,105 |
| | 121,958 |
| | (54,173 | ) | | 489,890 |
|
| Other revenue | 1,471 |
| | 24,988 |
| | (16,129 | ) | | 10,330 |
|
| Operating revenue | 423,576 |
| | 146,946 |
| | (70,302 | ) | | 500,220 |
|
| Gain (loss) on sale of assets | 1,488 |
| | (106 | ) | | — |
| | 1,382 |
|
| Gain (loss) on derivatives | (11,744 | ) | | — |
| | — |
| | (11,744 | ) |
| Total revenue | 413,320 |
| | 146,840 |
| | (70,302 | ) | | 489,858 |
|
| Operating expenses | | | | | | | |
| Lease operating | 79,884 |
| | — |
| | (16,129 | ) | | 63,755 |
|
| Transportation, processing and marketing | 70,324 |
| | 9,659 |
| | (58,941 | ) | | 21,042 |
|
| Midstream operating | — |
| | 24,719 |
| | — |
| | 24,719 |
|
| Cost of sales for purchased gathered production | — |
| | 34,529 |
| | — |
| | 34,529 |
|
| Production taxes | 19,455 |
| | — |
| | — |
| | 19,455 |
|
| Workovers | 2,652 |
| | 537 |
| | — |
| | 3,189 |
|
| Exploration | 52,354 |
| | — |
| | — |
| | 52,354 |
|
| Depreciation, depletion, and amortization | 120,617 |
| | 11,675 |
| | — |
| | 132,292 |
|
| Impairment of assets | 556,427 |
| | 348,866 |
| | — |
| | 905,293 |
|
| General and administrative | 59,897 |
| | 35,427 |
| | 12,331 |
| | 107,655 |
|
| Total operating expenses | 961,610 |
| | 465,412 |
| | (62,739 | ) | | 1,364,283 |
|
| Operating income | (548,290 | ) | | (318,572 | ) | | (7,563 | ) | | (874,425 | ) |
| Other income (expense) | | | | | | | |
| Interest expense | (49,823 | ) | | (11,636 | ) | | — |
| | (61,459 | ) |
| Interest income and other | 154 |
| | 17 |
| | 72 |
| | 243 |
|
| Equity in earnings of unconsolidated subsidiaries | — |
| | 6,216 |
| | — |
| | 6,216 |
|
| Reorganization items, net | 449 |
| | — |
| | (646 | ) | | (197 | ) |
| Total other income (expense) | (49,220 | ) | | (5,403 | ) | | (574 | ) | | (55,197 | ) |
| Income (loss) from continuing operations before income taxes | (597,510 | ) | | (323,975 | ) | | (8,137 | ) | — | (929,622 | ) |
| | | | | | | | |
| Interest expense | 49,823 |
| | 11,636 |
| | — |
| | 61,459 |
|
| Depreciation, depletion and amortization | 120,617 |
| | 11,675 |
| | — |
| | 132,292 |
|
| Loss on unrealized hedges | 19,386 |
| | — |
| | — |
| | 19,386 |
|
| Loss on sale of property and equipment | — |
| | 106 |
| | — |
| | 106 |
|
| Impairment assets | 556,427 |
| | 348,866 |
| | — |
| | 905,293 |
|
| Provision for uncollectible related party receivables | 886 |
| | 2,310 |
| | — |
| | 3,196 |
|
| Equity-based compensation | 5,718 |
| | 694 |
| | — |
| | 6,412 |
|
| Exploration | 52,354 |
| | — |
| | — |
| | 52,354 |
|
| Severance costs | 4,865 |
| | 2,162 |
| | — |
| | 7,027 |
|
| Strategic costs | 8,116 |
| | 11,479 |
| | 2,025 |
| | 21,620 |
|
| Non-cash lease operating expense | 3,835 |
| | — |
| | — |
| | 3,835 |
|
| Gain on equity method investment | — |
| | (5,503 | ) | | — |
| | (5,503 | ) |
| Reorganization items, net | (449 | ) | | — |
| | 646 |
| | 197 |
|
| Adjusted EBITDAX | $ | 224,068 |
| | $ | 59,450 |
| | $ | (5,466 | ) | | $ | 278,052 |
|
| | | | | | | | |
| Equity method investment | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Capital expenditures | 249,955 |
| | 77,612 |
| | — |
| | 327,567 |
|
| Total assets at period end | 396,041 |
| | 112,825 |
| | (10,286 | ) | | 498,580 |
|
|
| | | | | | | | | | | | | | | |
| | February 9, 2018 Through December 31, 2018 |
| (in thousands) | Exploration & Production | | Midstream | | Corporate and Eliminations | | Total |
| Revenue | | | | | | | |
| Oil | $ | 323,299 |
| | $ | — |
| | $ | — |
| | $ | 323,299 |
|
| Natural gas | 43,407 |
| | — |
| | — |
| | 43,407 |
|
| Natural gas liquids | 43,039 |
| | — |
| | — |
| | 43,039 |
|
| Sales of gathered production | — |
| | 31,506 |
| | — |
| | 31,506 |
|
| Midstream revenue | — |
| | 68,519 |
| | (41,059 | ) | | 27,460 |
|
| Segment sales revenue | 409,745 |
| | 100,025 |
| | (41,059 | ) | | 468,711 |
|
| Other revenue | 4,762 |
| | — |
| | — |
| | 4,762 |
|
| Operating revenue | 414,507 |
| | 100,025 |
| | (41,059 | ) | | 473,473 |
|
| Gain on sale of assets | 4,751 |
| | — |
| | — |
| | 4,751 |
|
| Gain (loss) on derivatives | (10,247 | ) | | — |
| | — |
| | (10,247 | ) |
| Total revenue | 409,011 |
| | 100,025 |
| | (41,059 | ) | | 467,977 |
|
| Operating expenses | | | | | | | |
| Lease operating | 60,547 |
| | — |
| | (3,720 | ) | | 56,827 |
|
| Transportation, processing and marketing | 50,038 |
| | 9,911 |
| | (40,656 | ) | | 19,293 |
|
| Midstream operating | — |
| | 15,221 |
| | — |
| | 15,221 |
|
| Cost of sales for purchased gathered production | — |
| | 31,247 |
| | — |
| | 31,247 |
|
| Production taxes | 16,865 |
| | — |
| | — |
| | 16,865 |
|
| Workovers | 5,563 |
| | — |
| | — |
| | 5,563 |
|
| Exploration | 34,085 |
| | — |
| | — |
| | 34,085 |
|
| Depreciation, depletion, and amortization | 133,554 |
| | 27,388 |
| | — |
| | 160,942 |
|
| Impairment of assets | 2,033,712 |
| | 1,171,339 |
| | — |
| | 3,205,051 |
|
| General and administrative | 114,735 |
| | 14,025 |
| | 2,292 |
| | 131,052 |
|
| Total operating expenses | 2,449,099 |
| | 1,269,131 |
| | (42,084 | ) | | 3,676,146 |
|
| Operating income | (2,040,088 | ) | | (1,169,106 | ) | | 1,025 |
| | (3,208,169 | ) |
| Other income (expense) | | | | | | | |
| Interest expense | (38,265 | ) | | (5,031 | ) | | — |
| | (43,296 | ) |
| Interest income and other | 1,983 |
| | 6 |
| | 60 |
| | 2,049 |
|
| Total other income (expense) | (36,282 | ) | | (5,025 | ) | | 60 |
| | (41,247 | ) |
| Income (loss) from continuing operations before income taxes | (2,076,370 | ) | | (1,174,131 | ) | | 1,085 |
| (1) | (3,249,416 | ) |
| | | | | | | | |
| Interest expense | 38,265 |
| | 5,031 |
| | — |
| | 43,296 |
|
| Depreciation, depletion and amortization | 133,554 |
| | 27,388 |
| | — |
| | 160,942 |
|
| Gain on unrealized hedges | (28,714 | ) | | — |
| | — |
| | (28,714 | ) |
| Loss on sale of fixed assets | 388 |
| | — |
| | — |
| | 388 |
|
| Impairment of assets | 2,033,712 |
| | 1,171,339 |
| | — |
| | 3,205,051 |
|
| Provision for uncollectible related party receivables | 22,438 |
| | — |
| | — |
| | 22,438 |
|
| Equity-based compensation | 20,000 |
| | 1,190 |
| | 835 |
| | 22,025 |
|
| Exploration | 34,085 |
| | — |
| | — |
| | 34,085 |
|
| Business Combination | 23,717 |
| | — |
| | — |
| | 23,717 |
|
| Adjusted EBITDAX | $ | 201,075 |
| | $ | 30,817 |
| | $ | 1,920 |
| | $ | 233,812 |
|
| | | | | | | | |
| Equity method investment | $ | — |
| | $ | 1,100 |
| | $ | — |
| | $ | 1,100 |
|
| Capital expenditures | 700,953 |
| | 61,807 |
| | — |
| | 762,760 |
|
| Total assets at period end | 935,719 |
| | 437,721 |
| | (15,610 | ) | | 1,357,830 |
|
_________________
| |
(1) | Includes $3,316 for elimination of intercompany deferred revenue resulting from the adoption of ASC 606. |
NOTE 27 — SUPPLEMENTAL OIL AND GAS DISCLOSURES(Unaudited)
We determined for 2018 reporting that it was not probable that we would have the necessary capital to develop our PUD reserves. Thus, we have concluded that we do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our available drilling locations.
The unaudited reserveSylvia J. Kerrigan and other information presented below is provided as supplemental information. The information presented during the 2018 Predecessor Period includes amounts related to discontinued operations.
Reserve estimatesMessrs. Donald R. Dimitrievich, Jeffrey H. Tepper, Donald R. Sinclair, David M. Leuschen and Pierre F. Lapeyre, Jr. are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.
Oil and gas producing activities are conducted onshoreindependent within the continental United States and all of our proved reserves are located within the United States.
Estimated Quantities of Proved Reserves
The following table sets forth our net proved reserves as of December 31, 2019 and 2018 and February 8, 2018, and the changes therein during the periods then ended.
|
| | | | | | | | | | | |
| | Oil (Mbbls) | | Gas (MMcf) | | NGL’s (Mbbls) | | Boe (Mbbls) |
| Total Proved Reserves: | |
| | |
| | |
| | |
| Balance at December 31, 2017 (Predecessor) | 73,518 |
| | 433,519 |
| | 36,887 |
| | 182,658 |
|
| Production | (521 | ) | | (1,984 | ) | | (161 | ) | | (1,012 | ) |
Sales of reserves in place (1) | (1,667 | ) | | (24,239 | ) | | (771 | ) | | (6,478 | ) |
| Revisions of previous quantity estimates and other | 375 |
| | 3,506 |
| | 289 |
| | 1,248 |
|
| Balance at February 8, 2018 (Predecessor) | 71,705 |
| | 410,802 |
| | 36,244 |
| | 176,416 |
|
Production(2) | (5,053 | ) | | (16,913 | ) | | (2,268 | ) | | (10,140 | ) |
Purchases in place(2) | 2,658 |
| | 13,331 |
| | 1,751 |
| | 6,631 |
|
Discoveries and extensions(2) | 30,026 |
| | 155,306 |
| | 19,646 |
| | 75,557 |
|
Revisions of previous quantity estimates and other(2) | (74,064 | ) | | (418,378 | ) | | (35,581 | ) | | (179,375 | ) |
| Balance at December 31, 2018 (Successor) | 25,272 |
| | 144,148 |
| | 19,792 |
| | 69,089 |
|
| Production | (5,885 | ) | | (24,802 | ) | | (2,760 | ) | | (12,779 | ) |
| Discoveries and extensions | 4,265 |
| | 24,351 |
| | 2,835 |
| | 11,159 |
|
Revisions of previous quantity estimates and other(3) | (6,736 | ) | | (29,254 | ) | | (9,352 | ) | | (20,964 | ) |
| Balance at December 31, 2019 (Successor) | 16,916 |
| | 114,443 |
| | 10,515 |
| | 46,505 |
|
| | | | | | | | |
| Proved Developed Reserves: | | | | | | | |
| Balance at December 31, 2017 | 20,347 |
| | 150,183 |
| | 12,180 |
| | 57,557 |
|
| Balance at February 8, 2018 | 19,345 |
| | 126,231 |
| | 11,348 |
| | 51,731 |
|
| Balance at December 31, 2018 | 25,272 |
| | 144,148 |
| | 19,792 |
| | 69,089 |
|
| Balance at December 31, 2019 | 16,916 |
| | 114,443 |
| | 10,515 |
| | 46,505 |
|
| Proved Undeveloped Reserves: | | | | | | | |
| Balance at December 31, 2017 | 53,171 |
| | 283,336 |
| | 24,707 |
| | 125,101 |
|
| Balance at February 8, 2018 | 52,360 |
| | 284,571 |
| | 24,896 |
| | 124,685 |
|
| Balance at December 31, 2018 | — |
| | — |
| | — |
| | — |
|
| Balance at December 31, 2019 | — |
| | — |
| | — |
| | — |
|
_________________
| |
(1) | Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to High Mesa and are classified as discontinued operations in our financial statements. |
| |
(2) | An analysis of changes in our reserves from February 8, 2018 to December 31, 2018 follows: |
|
| | | | | | | | |
| | MBoe |
| Description | Proved Developed Reserves | | Proved Undeveloped Reserves | | Total |
| Balance at February 8, 2018 | 51,731 |
| | 124,685 |
| | 176,416 |
|
| Production | (10,140 | ) | | — |
| | (10,140 | ) |
| Purchases in place, discoveries and extensions | 35,096 |
| | 47,092 |
| | 82,188 |
|
| Revisions of previous quantity estimates and other: | | | | | |
| Lower estimated recoveries identified as a result of 2018 drilling program | (31,964 | ) | | (69,534 | ) | | (101,498 | ) |
| Higher average commodity prices in Successor Period compared to 2017 | 5,367 |
| | 5,829 |
| | 11,196 |
|
| Transfers of PUDs to proved developed reserves | 18,999 |
| | (18,999 | ) | | — |
|
| Derecognition of PUDs due to significant concerns about ability to fund development of those reserves | — |
| | (89,073 | ) | | (89,073 | ) |
| Balance at December 31, 2018 | 69,089 |
| | — |
| | 69,089 |
|
| |
(3) | Revisions decreased our estimated recovery of proved reserves and is ratably due to lower average commodity prices in 2019 as compared to 2018, the decision to report ethane rejection rather than ethane recovery, and decreases in volume estimates based on the overall performance of our wells. |
Results of Operations for Oil and Gas Producing Activities - Upstream Segment
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Operating revenue | $ | 423,576 |
| | $ | 414,507 |
| | | $ | 40,136 |
|
Production expense (1) | 232,212 |
| | 247,748 |
| | | 30,743 |
|
| Depreciation, depletion and amortization | 120,617 |
| | 133,554 |
| | | 11,670 |
|
| Exploration expense | 52,354 |
| | 34,085 |
| | | 7,003 |
|
| Impairment expense | 556,427 |
| | 2,033,712 |
| | | — |
|
| Income tax expense (benefit) | — |
| | 4 |
| | | — |
|
| Results of operations | $ | (538,034 | ) | | $ | (2,034,596 | ) | | | $ | (9,280 | ) |
_________________ | |
(1) | Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and allocated general and administrative expense. |
Capitalized Costs Relating to Oil and Gas Producing Activities
|
| | | | | | | |
| | December 31, |
| (in thousands) | 2019 | | 2018 |
| Capitalized costs: | |
| | |
| Proved properties | $ | 2,239,444 |
| | $ | 2,110,346 |
|
| Unproved properties | 813,310 |
| | 816,282 |
|
| Total | 3,052,754 |
| | 2,926,628 |
|
| Accumulated depreciation, depletion, amortization and impairment | (2,837,402 | ) | | (2,163,291 | ) |
| Net capitalized costs | $ | 215,352 |
| | $ | 763,337 |
|
Costs Incurred in Oil and 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 and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
Costs incurred during the period: (1) | | | | | | |
|
| Property acquisition | | | | | | |
Unproved (2) | $ | — |
| | $ | 54,587 |
| | | $ | 4,240 |
|
| Proved | — |
| | 16,300 |
| | | 327 |
|
| Exploration | 7,305 |
| | 32,130 |
| | | 3,678 |
|
Development (3) | 134,908 |
| | 664,138 |
| | | 37,672 |
|
| | $ | 142,213 |
| | $ | 767,155 |
| | | $ | 45,917 |
|
_________________
| |
(1) | Costs incurred in the 2018 Predecessor Period include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. |
| |
(2) | Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million for the 2018 Successor Period. |
| |
(3) | Includes asset retirement additions (revisions) of $0.9 million and $5.6 million for the 2019 and the 2018 Successor Period, respectively. For the 2018 Predecessor Period, there were 0 material asset retirement additions (revisions). |
Standardized Measure of Discounted Future Net Cash Flows
The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic averagemeaning of the first-day-of-the-month, for the year ended December 31, 2019, the 2018 Successor Period, and for the 2018 Predecessor Period. Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. NASDAQ rules.
The following table sets forth the components of the standardized measure of discounted future net cash flows:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands, except per unit data) | December 31, 2019 | | December 31, 2018 | | | February 8, 2018 |
| Future cash inflows | $ | 1,326,490 |
| | $ | 2,446,888 |
| | | $ | 5,798,886 |
|
| Future production costs | (825,300 | ) | | (1,214,479 | ) | | | (2,556,361 | ) |
| Future development costs | (25,251 | ) | | (23,183 | ) | | | (965,780 | ) |
| Future income taxes | (26,707 | ) | | (146,632 | ) | | | — |
|
Future net cash flows(1) | 449,232 |
| | 1,062,594 |
| | | 2,276,745 |
|
| Discount to present value at 10 percent per annum | (122,321 | ) | | (348,311 | ) | | | (1,096,859 | ) |
| Standardized measure of discounted future net cash flows | $ | 326,911 |
| | $ | 714,283 |
| | | $ | 1,179,886 |
|
| Base price for crude oil, per barrel, in the above computation | $ | 55.69 |
| | $ | 65.56 |
| | | $ | 52.89 |
|
| Base price for gas, per Mcf, in the above computation | $ | 2.58 |
| | $ | 3.10 |
| | | $ | 2.99 |
|
| Realized price for NGLs, per barrel, in the above computation | $ | 14.60 |
| | $ | 22.44 |
| | | $ | 27.48 |
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Year Ended December 31, 2019 | | February 9, 2018
Through
December 31, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Balance at beginning of period | $ | 714,283 |
| | $ | 1,179,886 |
| | | $ | 1,105,922 |
|
| Sales and transfers of oil and gas produced, net of production costs | (253,582 | ) | | (278,091 | ) | | | (30,391 | ) |
| Net changes in prices and production costs | (270,712 | ) | | 38,963 |
| | | 71,334 |
|
| Revisions of previous quantity estimates | (129,305 | ) | | (1,120,097 | ) | | | 10,887 |
|
| Purchases of reserves in-place | — |
| | 24,376 |
| | | — |
|
Sales of reserves in-place(1) | — |
| | — |
| | | (4,807 | ) |
| Current year discoveries and extensions, less related costs | 134,451 |
| | 684,700 |
| | | — |
|
| Changes in estimated future development costs | 473 |
| | (39,069 | ) | | | 491 |
|
| Development costs incurred during the period | 84 |
| | 160,583 |
| | | — |
|
| Accretion of discount | 81,285 |
| | 117,989 |
| | | 110,592 |
|
| Net change in income taxes | 79,134 |
| | (98,568 | ) | | | — |
|
| Change in production rate (timing) and other | (29,200 | ) | | 43,611 |
| | | (84,142 | ) |
| Net change | (387,372 | ) | | (465,603 | ) | | | 73,964 |
|
| Balance at end of period | $ | 326,911 |
| | $ | 714,283 |
| | | $ | 1,179,886 |
|
_________________
| |
(1) | The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties. |
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rules 13a-15 and 15d-15 of the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, performed an evaluation of our disclosure controls and procedures. Our controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
We have concluded that our disclosure controls and procedures were effective as of December 31, 2019.
Management’s Annual Report on Internal Control Over Financial Reporting
Under the Exchange Act, our management is responsible for establishing and maintaining adequate internal control over financial reporting (“ICFR”). Our ICFR should be designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP and includes those policies and procedures that:
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of its assets;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and
provide reasonable assurance to prevent or timely detect unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.
As of December 31, 2019, management, including our principal executive officer and principal financial officer, and under the oversight of the Board of Directors, conducted an assessment of the effectiveness of our ICFR based upon the framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013) (COSO 2013).
Company Changes in ICFR in Response to Deficiencies Reported as of December 31, 2018
As disclosed in Part II Item 9A. Controls and Procedures in our Annual Report on Form 10-K for the year ended December 31, 2018, we concluded that our disclosure controls and procedures were not effective due to the existence of material weaknesses in our ICFR. Material weakness describes a deficiency, or a combination of deficiencies, in ICFR, such that there is a reasonable possibility that a material misstatement of the financial statements will not be prevented or detected on a timely basis.
During 2019, we implemented our remediations to address these material weaknesses, including by:
Adding to our senior management team with seasoned experience in performing risk assessments of ICFR in complex accounting and operating environments and implementing internal control in response to identified risks, which includes our chief financial officer and chief accounting officer. Each has a strong background in oil and gas accounting and managing sophisticated internal control assessments, including oversight of outside advisors.
Improving the cross-functional nature of our internal control environment by embedding ICFR at all levels and across finance and other departments which allowed us to better distribute accountability for ICFR. We provided GAAP and internal controls training to our employees with responsibilities for ICFR to improve internal control. As described above, we hired key finance and accounting positions during 2019 and we retained outside resources to supplement our employees with respect to complex accounting and financial reporting areas and improved our supervision of outside resources. We enhanced our documentation of procedures which resulted in a better understanding of roles and responsibilities for ICFR.
Engaging outside resources to assist with the design and implementation of a risk-based internal controls plan that aligns to and is measured against the COSO 2013 Framework. We used outside resources to assist our employees in business process documentation and ICFR design. Additionally, outside resources provided broad training and assisted with management's self-assessment and testing of internal controls. Due to the timing of the completion of our Annual Report for 2018, the addition of senior financial and accounting personnel and the improvements in our ICFR design, we were not able to perform rigorous interim testing of our 2019 control environment until the third quarter; therefore, our testing was performed primarily in the third and fourth quarters.
Performing a cross-functional enterprise risk assessment involving the executive management and all departments to adequately identify, analyze and determine how we will respond to our business operations, changes to them and the impact on financial reporting, including on ICFR. Our filing for bankruptcy protection in the third quarter restricted our ability to respond to a portion of our identified risks. Accordingly, we became subject to new risks associated with our bankruptcy filing, and we added employees and advisors knowledgeable in the bankruptcy process and communicated timely to those responsible for financial reporting, ICFR and those charged with governance regarding those risks.
Revising our processes, such as operating and capital accruals, or improving our controls over the use of spreadsheets used for impairment expense, depreciation, depletion and amortization expense, and determination of non-controlling interest among other accounts, such that access is restricted to appropriate personnel, that changes to data or formulas are authorized and appropriate, and that the spreadsheets are adequately reviewed by someone other than the preparer. As reported in the third quarter 2019 Form 10-Q, we satisfactorily completed testing of changes to access controls for payroll, production accounting and reserves systems to remediate material weaknesses identified during 2018 in those areas.
Addressing deficiencies in our financial reporting close process activities and related controls by proactively planning our response to accounting and disclosure requirements which allowed us to more fully develop disclosures and vet issues, implementing more robust review procedures of complex accounting and disclosure requirements, timely communicating requirements for financial disclosure as a result of the bankruptcy, and implementing reconciliation procedures and checklists to monitor completion of key processes and controls.
Deploying enhanced management review controls, performed by experienced employees, over complex accounting estimates at an appropriate level of precision to reduce the risk of an undetected material misstatement. We improved the controls over the completeness and accuracy of data and assumptions used in these accounting estimates, and where outside resources were used, improved our supervision of those resources.
Except for the remediation of the material weaknesses in internal control identified during the year ended December 31, 2018, there were no other changes in our ICFR during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information required as to Item 10 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference. Except as otherwise specifically incorporated by reference, our 2020 Proxy Statement is not deemed to be filed as part of this Annual Report.
Item 11. Executive Compensation
Information required as to Item 11 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required as to Item 12 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required as to Item 13 will be set forth in the 2020 Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 14. 14. Principal Accountant Fees and Services
KPMG LLP served as the Company’s independent auditor during 2019 and 2018.
Aggregate fees for professional services rendered to the CompanyInformation required by KPMG LLP were:
|
| | | | | | | | |
| | Year Ended December 31, 2019 | | | Year Ended December 31, 2018 |
| Audit fees | $ | 1,900,000 |
| | | $ | 2,966,500 |
|
| Audit-related fees | — |
| | | 359,000 |
|
| Tax fees | — |
| | | — |
|
| All other fees | — |
| | | — |
|
| Total | $ | 1,900,000 |
| | | $ | 3,325,500 |
|
Audit Fees. Audit fees are primarily for the auditthis section was provided in Part III, Item 14 of the Company’s consolidated financial statements included in the Annual Report on Form 10-K and reviews of the Company’s consolidated financial statements included in the Quarterly Reportsfiled on Form 10-Q. For the year ended December 31, 2018, KPMG also conducted an audit of the effectiveness of the Company’s internal control over financial reporting.March 5, 2020.
Audit-Related Fees. Audit-related fees were incurred for accounting consultation regarding certain transactions that occurred during the year ended December 31, 2018.
Tax Fees. KPMG did not provide income tax compliance, planning and advisory services to us during the years ended December 31, 2019 and 2018.
All Other Fees. KPMG did not provide any “other services” as the Company’s independent auditor during the years ended December 31, 2019 and 2018. Alta Mesa did pay KPMG LLP $162,670 for services on a state escheatment project covering the period from January 2017 through May 2018, but that contract was cancelled prior to engaging KPMG LLP as our independent auditor.
Pre-Approval Policy
Since the Business Combination, the Audit Committee of the Board of Directors approved all services to be provided by KPMG LLP.
PART IV
Item 15. Exhibits, and Financial StatementStatements and Schedules
| |
| (a) | The following documents are filed as part of this Annual Report or incorporated by reference: |
| |
| 1. | The Consolidated Financial Statements of Alta Mesa Resources, Inc. are listed on the Index to Financial Statements in Item 8. |
| |
2. | Financial Statement Schedules: |
| |
(i) | All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto. |
|
| |
2.1 | Contribution Agreement, dated as of August 16, 2017, among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, the Registrant and the Contributor Owners party thereto (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K filed with the SEC on August 17, 2017). |
2.2 |
|
2.3 |
|
3.1 | |
3.2 | |
3.3 | |
3.4 | |
3.5 | |
4.1 | |
4.2 |
|
4.3 | |
4.4 | |
4.5 | Registration Rights Agreement, dated as of February 9, 2018, by and among Alta Mesa Resources, Inc., High Mesa Holdings, L.P., KFM Holdco, LLC and Riverstone VI Alta Mesa Holdings, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018). |
4.6 | |
|
| |
4.7 | |
4.8 | |
4.9* | |
4.10* | Amended and Restated Purchase and Sale Agreement by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP and BCE-Mach III LLC and, with respect to certain provisions, Alta Mesa Resources, Inc., dated as of January 17, 2020. |
10.1 | |
10.2 | Master Assignment, Increase Agreement and Amendment No. 1 to Credit Agreement dated as of May 14, 2018 to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender, the Lenders listed therein and Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on November 14, 2018). |
10.3 |
|
10.4 | Amendment No. 3 to Credit Agreement dated as of December 5, 2018 but effective as of February 9, 2018, to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender and the Lenders listed therein (incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K filed with the SEC on August 27, 2019). |
10.5 | Amended and Restated Credit Agreement, dated May 30, 2018, by and among Kingfisher Midstream, LLC, as borrower, Wells Fargo Bank, N.A., as successor administrative agent and LC issuer, and ABN AMRO Capital USA LLC, as resigning administrative agent, the LC issuers listed therein, the Lenders listed therein and the Exiting lenders listed therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 31, 2018). |
10.6 | First Amendment and Limited Waiver to Amended and Restated Credit Agreement dated as of April 29, 2019, among Kingfisher Midstream, LLC, each of the lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent and an issuer of letters of credit, to that certain Amended and Restated Credit Agreement dated as of May 30, 2018 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1, 2019). |
10.7 | |
10.8 | |
10.9 | |
10.10 | |
10.11 | |
|
| |
10.12 | |
10.13 | |
10.14 | |
10.15 | |
10.16 | |
10.17 | |
10.18 | |
10.19 | |
10.20 | |
10.21 | |
10.22 |
|
10.23 | Amended and Restated Voting Agreement, by and among Alta Mesa Holdings GP, LLC, BCE-AMH Holdings, LLC, BCE-MESA Holdings, 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., United Insurance Company of America, Jade Real Assets Fund, Michael E. Ellis, Harlan H. Chappelle and SRII Opco, LP, dated as of February 9, 2018 (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 9, 2018). |
10.24* | |
10.25 | |
10.26 |
|
21.1* | |
|
| |
| 31.1* | |
| 31.2* | |
32.1* | |
32.2* | |
99.1* | |
101* | Inline Interactive data files. |
104* | Cover page Inline interactive data file |
| * filed herewith. |
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| | | ALTA MESA RESOURCES, INC. |
| | | (Registrant) |
| | | | |
| By: | /s/ Curtis M. Emerson | | |
| | Curtis M. Emerson | | |
| | Vice President and Chief Accounting Officer (Principal Accounting Officer) | | |
| | | | |
| Dated: | March 5,April 14, 2020 | | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 5, 2020 by the following persons on behalf of the registrant and in the capacities indicated. |
| | | |
| Signature | | Title |
| | | |
By: | /s/ Mark P. Castiglione | | Chief Executive Officer (Principal Executive Officer) |
| Mark P. Castiglione | | |
| | | |
By: | /s/ John C. Regan | | Executive Vice President, Chief Financial Officer and Assistant Secretary (Principal Financial Officer) |
| John C. Regan | | |
| | | |
By: | /s/ James T. Hackett | | Chairman of the Board and Director |
| James T. Hackett | | |
| | | |
By: | /s/ Donald R. Dimitrievich | | Director |
| Donald R. Dimitrievich | | |
| | | |
By: | /s/ William W. McMullen | | Director |
| William W. McMullen | | |
| | | |
By: | /s/ Pierre F. Lapeyre, Jr. | | Director |
| Pierre F. Lapeyre, Jr. | | |
| | | |
By: | /s/ Jeffrey H. Tepper | | Director |
| Jeffrey H. Tepper | | |
| | | |
By: | /s/ Diana J. Walters | | Director |
| Diana J. Walters | | |
| | | |
By: | /s/ Sylvia J. Kerrigan | | Director |
| Sylvia J. Kerrigan | | |
| | | |
By: | /s/ David M. Leuschen | | Director |
| David M. Leuschen | | |
| | | |
By: | /s/ Donald R. Sinclair | | Director |
| Donald R. Sinclair | | |
