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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
_____________________________________
FORM 10-Q
_____________________________________

   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2019
OR
   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)
_______________________________________
Delaware
81-4433840
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
 

 
15021 Katy Freeway,
Suite 400,
Houston,
Texas
77094
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: 281-530-0991
Securities registered pursuant to Section 12(b) of the Act: None.
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      No  
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      No    
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.
Large accelerated filer


Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 

As of October 31, 2019, there were 182,774,952 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 528,041 nonvested restricted stock awards outstanding as of October 31, 2019.
 



TABLE OF CONTENTS
 
 
 
 
Page Number
PART I - FINANCIAL INFORMATION
 
                   Condensed Consolidated Statements of Operations
                   Condensed Consolidated Balance Sheets
                   Condensed Consolidated Statements of Cash Flows
                   Notes to Condensed Consolidated Financial Statements
PART II - OTHER INFORMATION
 


Table of Contents

Glossary of Terms

The definitions and abbreviations set forth below apply to the indicated terms throughout this filing.
Company Specific Terms -
 
2018 10-K -
Alta Mesa Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2018.
2018 Period -
The combined Successor Period from February 9, 2018 through September 30, 2018 and Predecessor Period from January 1, 2018 through February 8, 2018.
2019 Period -
The nine months ended September 30, 2019.
2024 Notes -
$500 million aggregate principal amount of 7.875% senior unsecured notes maturing December 2024.
Alta Mesa -
Alta Mesa Holdings, LP. This entity 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.
Alta Mesa Services -
Alta Mesa Services, LP, a wholly owned subsidiary of Alta Mesa Holdings, LP.
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.
ARM -
ARM Energy Management, LLC, a company that marketed our oil and gas production and provided 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 Kingfisher Midstream, LLC.
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.
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.
KFM -
Kingfisher Midstream, LLC. This entity 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.
Midstream -
Reportable business segment representing our midstream activities.
Predecessor Period -
The period from January 1, 2018 through February 8, 2018.
PSU's -
Performance-based restricted stock units issued to employees under the Alta Mesa Resources, Inc. 2018 Long-Term Incentive Plan.
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.
Successor Period -
The period from February 9, 2018 through September 30, 2018, and all periods thereafter.
Upstream -
Reportable business segment representing our exploration and production activities.
Oil, Gas and Other Terms -
 
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.

i

Table of Contents

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.
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 project -
A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
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.
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.
Enhanced recovery -
The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -
A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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.
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.

ii

Table of Contents

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.
MMBbl -
One million barrels of crude oil, condensate or natural gas liquids.
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.
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.
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.
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.
Realized price -
The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -
The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -
Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.
Resources -
Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
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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Table of Contents

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.
Unproved properties -
Properties with no proved reserves.
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.


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Table of Contents

Cautionary Statement Regarding Forward-Looking Statements
The information in this Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our ability to continue as a going concern, the outcome or timing of our emergence from bankruptcy, 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 Quarterly 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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 10-K”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about:
our ability to continue as a going concern;
the outcome or timing of our emergence from bankruptcy, including limitations placed upon us by the process and our ability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring or sale transaction;
our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;
the sufficiency of liquidity to fund our operations and capital expenditures;
our access to capital, including constraints from the cost and availability of debt and equity financing;
our ability to comply with, or amend the terms of, the covenants and restrictions imposed by the KFM Credit Facility;
our ability to execute our stated business strategy;
our reserve quantities and the present value of our reserves;
our ability to replace the reserves we produce through drilling and through acquisitions;
our exploration and drilling prospects, inventories, projects and programs;
our drilling, completion and production technology;
future oil and gas prices;
the supply and demand for our production and our midstream services;
the timing and amount of our future production;
our hedging strategy and expected results;
competition and government regulation;
our ability to obtain permits and governmental approvals;
expected or anticipated regulatory changes, including to the Oklahoma forced pooling system;
pending legal and environmental matters;
our future drilling plans, spacing plans and development pace;
our marketing of our production;
our leasehold or business acquisitions;
our costs of developing our properties;
our ability to hire, train or retain qualified personnel;
general economic conditions;
operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids and crude oil;
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;
our ability to collect receivables from High Mesa, Inc. and its subsidiaries; and
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

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, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the ability to confirm and consummate

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a plan of reorganization; risks attendant to the bankruptcy process, including the effects thereof on our business and on the interests of various constituents, the length of time that we might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings; risks associated with third party motions in any bankruptcy case, which may interfere with the ability to confirm and consummate a plan of reorganization; potential adverse effects on our liquidity or results of operations; increased costs to execute the reorganization; our ability to negotiate a waiver under the KFM Credit Facility and the ability of the KFM lenders to accelerate the repayment of KFM’s borrowings; effects on the market price of our common stock and on our ability to access the capital markets; 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, liabilities resulting from litigation or the SEC investigation, difficulties in obtaining necessary approvals and permits, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described in Risk Factors in this Quarterly Report and in our 2018 10-K.

Estimating reserve quantities of oil, natural gas and NGLs is complex, inexact and 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 making a number of economic assumptions, such as sales prices, the relative mix of oil, natural gas and NGLs that will be ultimately produced, drilling and operating costs, 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 assumptions used in our estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of development and related production. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report or in the 2018 10-K 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 Quarterly Report.


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Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(in thousands, except shares outstanding and per share data)

Successor
 
 
Predecessor

Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Revenue
 
 
 
 
 
 
 
 
 
 
 
Oil
$
84,010

 
$
107,253

 
 
$
261,041

 
$
222,822

 
 
$
30,972

Natural gas
10,788

 
11,959

 
 
41,622

 
25,149

 
 
4,276

Natural gas liquids
8,333

 
13,880

 
 
29,800

 
28,835

 
 
4,000

Sales of gathered production
8,387

 
9,129

 
 
28,386

 
21,926

 
 

Midstream revenue
5,882

 
7,802

 
 
19,586

 
17,879

 
 

Other
2,143

 
1,011

 
 
8,242

 
3,795

 
 
888

Operating revenue
119,543

 
151,034

 
 
388,677

 
320,406

 
 
40,136

Gain (loss) on sale of assets
(106
)
 
(18
)
 
 
1,377

 
5,058

 
 
840

Gain (loss) on derivatives
(379
)
 
(11,212
)
 
 
(11,744
)
 
(62,442
)
 
 
6,663

Total revenue
119,058

 
139,804

 
 
378,310

 
263,022

 
 
47,639

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
Lease operating
14,192

 
16,351

 
 
49,250

 
37,347

 
 
4,408

Transportation, processing and marketing
6,179

 
5,181

 
 
17,619

 
13,936

 
 
3,725

Midstream operating
6,621

 
4,507

 
 
19,292

 
8,407

 
 

Cost of sales for purchased gathered production
7,656

 
9,461

 
 
26,071

 
22,172

 
 

Production taxes
4,673

 
6,311

 
 
15,273

 
10,332

 
 
953

Workovers
783

 
1,065

 
 
1,903

 
2,643

 
 
423

Exploration
40,847

 
1,029

 
 
46,190

 
10,697

 
 
7,003

Depreciation, depletion and amortization
36,999

 
53,103

 
 
112,907

 
102,716

 
 
11,670

Impairment of assets
691,123

 

 
 
697,623

 

 
 

General and administrative
27,992

 
11,902

 
 
84,682

 
72,110

 
 
21,234

Total operating expenses
837,065

 
108,910

 
 
1,070,810

 
280,360

 
 
49,416

Operating income
(718,007
)
 
30,894

 
 
(692,500
)
 
(17,338
)
 
 
(1,777
)
Other income (expense)
 
 
 
 
 
 
 
 
 
 
 
Interest expense
(15,145
)
 
(12,347
)
 
 
(47,360
)
 
(29,570
)
 
 
(5,511
)
Interest income
69

 
357

 
 
199

 
1,727

 
 
172

Equity in earnings of unconsolidated subsidiaries
(29
)
 

 
 
713

 

 
 

Reorganization items, net
22,467

 

 
 
22,467

 

 
 

Total other income (expense), net
7,362

 
(11,990
)
 
 
(23,981
)
 
(27,843
)
 
 
(5,339
)
Income (loss) from continuing operations before income taxes
(710,645
)
 
18,904

 
 
(716,481
)
 
(45,181
)
 
 
(7,116
)
Income tax provision (benefit)

 
1,504

 
 

 
(6,161
)
 
 

Income (loss) from continuing operations
(710,645
)
 
17,400

 
 
(716,481
)
 
(39,020
)
 
 
(7,116
)
Loss from discontinued operations, net of tax

 

 
 

 

 
 
(7,746
)
Net income (loss)
(710,645
)
 
17,400

 
 
(716,481
)
 
(39,020
)
 
 
$
(14,862
)
Net income (loss) attributable to noncontrolling interests
(368,458
)
 
10,427

 
 
(368,132
)
 
(26,063
)
 
 
 
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders
$
(342,187
)
 
$
6,973

 
 
$
(348,349
)
 
$
(12,957
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Attributable to Alta Mesa Resources, Inc. stockholders:
 
 
 
 
 
 
 
 
 
 
 
Income (loss) per share - basic
$
(1.87
)
 
$
0.04

 
 
$
(1.92
)
 
$
(0.07
)
 
 
 
Income (loss) per share - diluted
$
(1.87
)
 
$
0.04

 
 
$
(1.92
)
 
$
(0.08
)
 
 
 

The accompanying notes are an integral part of these financial statements.

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Table of Contents

ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands, except shares and per share data)
໿

September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
69,325

 
$
26,854

Restricted cash
951

 
1,001

Accounts receivable, net
66,386

 
87,842

Other receivables
1,171

 
6,331

Related party receivables, net

 
3,341

Prepaid expenses and other
9,784

 
1,125

Derivatives

 
16,423

Total current assets
147,617

 
142,917

Property and equipment, net
 
 
 
Oil and gas properties, successful efforts method
365,343

 
763,337

Other property and equipment
166,575

 
444,269

Total property and equipment, net
531,918

 
1,207,606

Other assets
 
 
 
Operating lease right-of-use assets, net
7,402

 

Equity method investment
1,813

 
1,100

Deferred financing costs, net
1,720

 
3,195

Deposits and other long-term assets
6,597

 
65

Derivatives

 
2,947

Total other assets
17,532

 
7,307

Total assets
$
697,067

 
$
1,357,830




September 30, 2019
 
December 31, 2018
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Current portion of debt
$
564,004

 
$
690,123

Accounts payable and accrued liabilities
61,001

 
247,439

Advances from non-operators
619

 
5,193

Advances from related party
2,611

 
9,839

Asset retirement obligations, current portion
74

 
2,079

Current operating lease liability
736

 

Derivatives

 
1,710

Total current liabilities
629,045

 
956,383

Long-term liabilities
 
 
 
Asset retirement obligations, net of current portion
12,868

 
9,473

Long-term debt, net

 
174,000

Operating lease liabilities, net of current portion
10,781

 

Derivatives

 
180

Other long-term liabilities
6,662

 
1,667

Total long-term liabilities
30,311

 
185,320

Liabilities subject to compromise
533,181

 

Total liabilities 
1,192,537

 
1,141,703

          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

 

Common stock, $0.0001 par value
 
 
 
Class A: 1,200,000,000 shares authorized; 182,765,278 shares issued and outstanding (180,072,227 issued and outstanding at December 31, 2018)
18

 
18

Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at September 30, 2019 and December 31, 2018
20

 
20

Additional paid in capital
1,511,330

 
1,503,382

Accumulated deficit
(1,881,162
)
 
(1,532,813
)
Total stockholders’ equity
(369,794
)
 
(29,393
)
Noncontrolling interests
(125,676
)
 
245,520

Total equity
(495,470
)
 
216,127

Total liabilities and stockholders’ equity
$
697,067

 
$
1,357,830

The accompanying notes are an integral part of these financial statements.
 


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Table of Contents

ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)

Successor
 
 
Predecessor

Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Cash flows from operating activities:
 
 
 
 
 
 
Net loss
$
(716,481
)
 
$
(39,020
)
 
 
$
(14,862
)
Adjustments to reconcile net loss to cash from operating activities:
 
 
 
 
 
 
Depreciation, depletion and amortization
112,907

 
102,716

 
 
12,554

Non-cash lease expense
2,343

 

 
 

Provision for uncollectible receivables
3,449

 

 
 

Impairment of assets
697,623

 

 
 
5,560

Non-cash reorganization items, net
(25,142
)
 

 
 

Amortization of deferred financing costs
541

 
339

 
 
171

Amortization of debt premium
(3,432
)
 
(3,281
)
 
 

Equity-based compensation expense
5,025

 
8,333

 
 

Non-cash exploration expense
40,245

 
7,288

 
 
4,575

(Gain) loss on derivatives
11,744

 
62,442

 
 
(6,663
)
Cash settlements of derivatives
7,642

 
(32,201
)
 
 
(2,296
)
Cash paid for derivatives
(1,906
)
 

 
 

Interest converted into debt

 

 
 
103

Interest added to notes receivable from affiliate

 
(680
)
 
 
(85
)
Deferred tax provision (benefit)

 
(5,378
)
 
 

Loss on sale of fixed assets
105

 
81

 
 
1,923

Equity in earnings of unconsolidated subsidiaries
(713
)
 

 
 

Impact on cash from changes in:
 
 
 
 
 
 
Accounts receivable
21,193

 
(16,225
)
 
 
(21,184
)
Other receivables
5,161

 
972

 
 
(662
)
Related party receivables
154

 
(14,488
)
 
 
(117
)
Prepaid expenses and other assets
(15,190
)
 
8,368

 
 
(591
)
Advances from related party
(7,231
)
 
(30,589
)
 
 
24,116

Settlement of asset retirement obligations

(180
)
 
(1,249
)
 
 
(63
)
Accounts payable, accrued liabilities and other liabilities
(6,135
)
 
(44,922
)
 
 
23,857

Operating lease obligations
(2,270
)
 

 
 

Cash from operating activities
129,452

 
2,506

 
 
26,336

Cash flows from investing activities:
 
 
 
 
 
 
Capital expenditures
(315,894
)
 
(523,645
)
 
 
(36,695
)
Acquisitions, net of cash acquired

 
(791,819
)
 
 
(1,218
)
Proceeds withdrawn from trust account

 
1,042,742

 
 

Investment in equity affiliate and other, net

 
(9,326
)
 
 

Cash from investing activities
(315,894
)
 
(282,048
)
 
 
(37,913
)
Cash flows from financing activities:
 
 
 
 
 
 
Proceeds from long-term debt borrowings
238,500

 
162,500

 
 
60,000

Repayments of long-term debt
(9,496
)
 
(193,565
)
 
 
(43,000
)
Payment of taxes withheld on equity-based compensation awards
(141
)
 

 
 

Deferred financing costs paid

 
(3,716
)
 
 

Purchase and retirement of Class A common shares

 
(14,750
)
 
 

Capital 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
228,863

 
312,211

 
 
16,932

Net increase in cash, cash equivalents and restricted cash
42,421

 
32,669

 
 
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
$
70,276

 
$
33,057

 
 
$
10,345

The accompanying notes are an integral part of these financial statements.

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Table of Contents

ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED 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

Equity based compensation expense

 

 

 

 

 

 
3,466

 

 
3,466

 

 
3,466

Net loss

 

 

 

 

 

 

 
(13,330
)
 
(13,330
)
 
(20,424
)
 
(33,754
)
Balance at March 31, 2018
169,372

 
17

 

 

 
213,402

 
21

 
1,402,888

 
(21,444
)
 
1,381,482

 
2,038,211

 
3,419,693

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
9,589

 
1

 

 

 
(9,589
)
 
(1
)
 
90,872

 

 
90,872

 
(91,309
)
 
(437
)
Restricted stock awards vested
98

 

 

 

 

 

 

 

 

 

 

Equity based compensation expense

 

 

 

 

 

 
4,263

 

 
4,263

 

 
4,263

Net loss

 

 

 

 

 

 

 
(6,600
)
 
(6,600
)
 
(16,066
)
 
(22,666
)
Balance at June 30, 2018
179,059

 
18

 

 

 
204,922

 
20

 
1,498,023

 
(28,044
)
 
1,470,017

 
1,939,594

 
3,409,611

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
)
Adjustment to valuation allowance related to prior redemption of noncontrolling interests and Class C common shares for Class A common shares

 

 

 

 

 

 
(468
)
 

 
(468
)
 

 
(468
)
Equity-based compensation expense

 

 

 

 

 

 
604

 

 
604

 

 
604

Net income

 

 

 

 

 

 

 
6,973

 
6,973

 
10,427

 
17,400

Balance at September 30, 2018
175,957

 
$
18

 

 
$

 
204,922

 
$
20

 
$
1,472,570

 
$
(21,071
)
 
$
1,451,537

 
$
1,960,860

 
$
3,412,397


The accompanying notes are an integral part of these financial statements.


6

Table of Contents

ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED 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 January 1, 2019
180,072

 
$
18

 

 
$

 
202,170

 
$
20

 
$
1,503,382

 
$
(1,532,813
)
 
$
(29,393
)
 
$
245,520

 
$
216,127

Restricted stock awards vested, net of taxes
338

 

 

 

 

 

 
67

 

 
67

 
(209
)
 
(142
)
Equity-based compensation expense

 

 

 

 

 

 
2,679

 

 
2,679

 

 
2,679

Net loss

 

 

 

 

 

 

 
(8,407
)
 
(8,407
)
 
(9,028
)
 
(17,435
)
Balance at March 31, 2019
180,410

 
18

 

 

 
202,170

 
20

 
1,506,128

 
(1,541,220
)
 
(35,054
)
 
236,283

 
201,229

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
44

 

 

 

 

 

 
(8
)
 

 
(8
)
 
(15
)
 
(23
)
Equity-based compensation

 

 

 

 

 

 
840

 

 
840

 

 
840

Net income

 

 

 

 

 

 

 
2,245

 
2,245

 
9,354

 
11,599

Balance at June 30, 2019
182,636

 
18

 

 

 
199,988

 
20

 
1,509,716

 
(1,538,975
)
 
(29,221
)
 
242,866

 
213,645

Restricted stock awards vested, net of taxes
129

 

 

 

 

 

 
108

 

 
108

 
(84
)
 
24

Equity-based compensation

 

 

 

 

 

 
1,506

 

 
1,506

 

 
1,506

Net loss

 

 

 

 

 

 

 
(342,187
)
 
(342,187
)
 
(368,458
)
 
(710,645
)
Balance at September 30, 2019
182,765

 
$
18

 

 
$

 
199,988

 
$
20

 
$
1,511,330

 
$
(1,881,162
)
 
$
(369,794
)
 
$
(125,676
)
 
$
(495,470
)

The accompanying notes are an integral part of these financial statements.



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ALTA MESA RESOURCES, INC. (Debtor-in-possession)
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)
(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.

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ALTA MESA RESOURCES, INC. (Debtor-in-possession)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Description of Business and Business Combination
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 acquisition, development, exploration and production 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 generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are vital to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.

We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, exchange, acquisition, purchase, reorganization or similar business combination involving it and one or more businesses. On February 9, 2018 we acquired 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”, and changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”

In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and associated liabilities to its prior owner, High Mesa Holdings, LP (“High Mesa”). The non-STACK assets and liabilities are reflected as discontinued operations in the Predecessor portion of our financial statements.

As a result of our failure to comply with the continued listing requirements of the NASDAQ Capital Market (“NASDAQ”), trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively. 

Bankruptcy Accounting
As discussed further in Note 3, on September 11, 2019, AMR, Alta Mesa, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and together with AMR, the “Debtors”) filed voluntary petitions (“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 Debtors will 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 condensed 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 the Company’s condensed consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s condensed consolidated balance sheet at September 30, 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 condensed consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the condensed consolidated 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 the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business. While operating as debtor-in-possession under Chapter 11 of the Bankruptcy Code, the Company may sell or otherwise dispose of or liquidate

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assets or settle liabilities in amounts other than those reflected on its condensed 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 the Company’s historical condensed consolidated financial statements.

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 us to meet our obligations apart from cash held by our subsidiaries. In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Basis of Presentation

These financial statements include the consolidated financial positions, results of operations and cash flows of the Company, the AMH Debtors and our non-debtor subsidiaries, which are controlled by us. All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation of the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation. 

NOTE 2 — SUMMARY OF RECENTLY ISSUED ACCOUNTING STANDARDS APPLICABLE TO US

Adopted
Effective January 1, 2019, we adopted ASU 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. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to 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. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data, (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses and (iii) provide additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. Based on a tentative decision by the FASB, we expect this standard, including related amendments, will be effective for us beginning January 2023. No determination has yet been made of the impact of this new standard on our financial position or results of operations.


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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 no earlier than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and expect to apply the new standard prospectively to implementation costs incurred after the date of adoption.

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 no earlier than January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

NOTE 3 - CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11
On September 11, 2019, the Debtors filed the Bankruptcy Petitions for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The 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.

Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries, Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC, (together the “non-Debtors”) are not in bankruptcy or otherwise part of the Chapter 11 cases at this time.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the AMH Debtors’ debt obligations, the creditors are stayed from taking any actions against the AMH Debtors as a result of such defaults, subject to certain limited exceptions provided by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the AMH Debtors’ prepetition liabilities are subject to compromise under the Bankruptcy Code.

Initial Orders and Other Filings

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors have been authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The current cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral until November 21, 2019 on the terms and conditions agreed by the AMH Debtors and their creditors (including the lenders under the Alta Mesa RBL) as set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain other milestones related to sale of the Debtor assets. The continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

On September 27, 2019, the United States Trustee for the Southern District of Texas appointed an official committee of unsecured creditors. On October 18, 2019, the Debtors filed schedules and statements with the Bankruptcy Court setting forth,

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among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Except as otherwise provided by the Bankruptcy Court, proofs of prepetition claims, including those arising from subsequent rejection of executory contracts and unexpired leases, must be on file by December 9, 2019, or by March 9, 2020, in the case of claims by governmental units. Differences between amounts scheduled by the Debtors and claims by creditors will be evaluated and resolved in connection with the claims resolution process.

The Debtors are in a marketing process to sell their assets along with KFM’s midstream assets. On October 11, 2019, the Bankruptcy Court entered an order approving, among other things, proposed bidding procedures and the dates for an auction, a hearing to approve the sale or sales of assets, and related dates and deadlines. The auction is scheduled to occur on January 8, 2020 and the sale hearing is scheduled to occur on January 10, 2020. Both of the scheduled dates are subject to postponement.

Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the crude oil and gas gathering agreements are subject to rescission as the products of breaches of fiduciary duty, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, 2019.

Liabilities Subject to Compromise
Liabilities subject to compromise represent the Debtors’ prepetition liabilities that have been allowed or that the Debtors anticipate will be allowed as claims in its Chapter 11 cases. The amounts represent the Debtors’ current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities the Debtors has estimated and the claims filed, or to be filed, will be evaluated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 proceedings and adjust as necessary.

Following are the components of liabilities subject to compromise included on the condensed consolidated balance sheet:
(in thousands)
September 30, 2019
2024 Notes
$
500,000

Accounts payable and accrued liabilities
21,670

Accrued interest payable on 2024 Notes
9,515

Operating lease liabilities
1,996

Liabilities subject to compromise
$
533,181



Reorganization Items
The Company has incurred and is expected to continue to incur significant costs associated with the bankruptcy. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date and also includes adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.

Following are the components of reorganization items, net included in our Condensed Consolidated Statements of Operations:


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(in thousands)
Three Months Ended September 30, 2019
 
Nine Months Ended September 30, 2019
Unamortized deferred financing fees and premiums
$
24,748

 
$
24,748

Terminated contracts
394

 
394

Legal and other professional advisory fees
(2,675
)
 
(2,675
)
Reorganization items, net
$
22,467

 
$
22,467



Interest Expense
Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to cover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. The Company did not record interest expense on its 2024 Notes for the period September 12, 2019 through September 30, 2019. For that period, the unrecorded contractual interest was approximately $2.0 million.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Debtors in this Quarterly Report on Form 10-Q, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the applicable Debtor, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

On September 26, 2019, the Bankruptcy Court approved our request to reject an office lease extending through November 2023. Pursuant to this rejection, we de-recognized the right-of-use asset and liability, which resulted in a gain of $0.4 million (included in reorganization items, net). In October 2019, an additional lease and other less significant contracts were also rejected by the Bankruptcy Court. Pursuant to this rejection, we reported the corresponding current and long-term lease liability as liabilities subject to compromise at September 30, 2019.















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Condensed Combined Financial Information of Debtors
Combined Statement of Operations (Unaudited)
(in thousands)
Three Months Ended September 30, 2019
 
Nine Months Ended September 30, 2019
Revenue
 
 
 
Oil
$
84,010

 
$
261,041

Natural gas
10,788

 
41,622

Natural gas liquids
8,333

 
29,800

Other
302

 
1,200

Operating revenue
103,433

 
333,663

Gain on sale of assets

 
1,483

Loss on derivatives
(379
)
 
(11,744
)
Total revenue
103,054

 
323,402

Operating expenses


 


Lease operating
18,071

 
62,302

Transportation and marketing
17,561

 
54,936

Production taxes
4,673

 
15,273

Workovers
757

 
1,366

Exploration
40,847

 
46,190

Depreciation, depletion and amortization
33,407

 
102,586

Impairment of assets
387,721

 
394,221

General and administrative
19,781

 
62,869

Total operating expenses
522,818

 
739,743

Operating income
(419,764
)
 
(416,341
)
Other income (expenses)


 


Interest expense
(12,233
)
 
(39,134
)
Interest income
45

 
126

Reorganization items, net
22,467

 
22,467

Total other income (expense), net
10,279

 
(16,541
)
Loss from continuing operations before income taxes
(409,485
)
 
(432,882
)
Net loss
$
(409,485
)
 
$
(432,882
)

















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Table of Contents

Combined Balance Sheet (Unaudited)
(in thousands)
September 30, 2019
ASSETS
 
Current assets
 
Cash and cash equivalents
$
58,143

Restricted cash
951

Accounts receivable, net
55,666

Other receivables
1,171

Related party receivables, net
17,419

Note receivables from related parties, net

Prepaid expenses and other current assets
6,948

Total current assets
140,298

Property and equipment, net
 
Oil and gas properties, successful efforts method
365,343

Other property and equipment
36,818

Total property and equipment, net
402,161

Other assets
 
Investment in subsidiary
1,504,147

Operating lease right-of-use assets, net
7,113

Deposits and other long-term assets
6,171

Total other assets
1,517,431

Total assets
$
2,059,890

 
 
LIABILITIES AND PARTNERS’ CAPITAL
 
Current liabilities
 
Current portion of debt
$
340,004

Accounts payable and accrued liabilities
51,722

Accounts payable - related parties
18,301

Advances from non-operators
619

Advances from related party
2,607

Asset retirement obligations, current portion
74

Current operating lease liability
650

Total current liabilities
413,977

Long-term liabilities

Asset retirement obligations, net of current portion
12,717

Operating lease liabilities, net of current portion
10,569

Total long-term liabilities
23,286

Liabilities subject to compromise
533,181

Total liabilities
970,444

Partners’ capital
1,089,446

Total liabilities and partners’ capital
$
2,059,890







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Combined Statement of Cash Flows (Unaudited)
(in thousands)
Nine Months Ended September 30, 2019
Cash flows from operating activities:
 
Net loss
$
(432,882
)
Adjustments to reconcile net loss to cash from operating activities:
 
Depreciation, depletion and amortization
102,586

Non-cash lease expense
2,216

Provision for uncollectible receivables
1,139

Impairment of assets
394,221

Non-cash reorganization items, net
(25,142
)
Amortization of deferred financing costs
195

Amortization of debt premium
(3,432
)
Equity-based compensation expense
4,453

Non-cash exploration expense
40,245

(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
12,441

Other receivables
5,097

Related party receivables
3,826

Prepaid expenses and other assets
(12,127
)
Advances from related party
(7,215
)
Settlement of asset retirement obligations
(180
)
Accounts payable, accrued liabilities and other liabilities
8,494

Operating lease obligations
(2,151
)
Cash from operating activities
109,264

Cash flows from investing activities:
 
Capital expenditures
(243,709
)
Distribution received from subsidiary
691

Cash from investing activities
(243,018
)
Cash flows from financing activities:
 
Proceeds from long-term debt borrowings
183,500

Repayments of long-term debt
(4,496
)
Payment of taxes withheld on equity-based compensation awards
(141
)
Cash from financing activities
178,863

Net increase in cash, cash equivalents and restricted cash
45,109

Cash, cash equivalents and restricted cash, beginning of period
13,985

Cash, cash equivalents and restricted cash, end of period
$
59,094





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NOTE 4 — IMPAIRMENT OF ASSETS
 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Upstream
 
 
 
 
 
 
 
 
 
 
 
Impairment of proved properties
$
387,721

 
$

 
 
$
387,721

 
$

 
 
$

Impairment of operating lease right-of-use assets

 

 
 
6,500

 

 
 

Total Upstream impairment of assets
387,721

 

 
 
394,221

 

 
 

Midstream
 
 
 
 
 
 
 
 
 
 
 
Impairment of property and equipment
303,402

 

 
 
303,402

 

 
 

Total Midstream impairment of assets
303,402

 

 
 
303,402

 

 
 

 
 
 
 
 
 
 
 
 
 
 
 
Total impairment of assets
$
691,123

 
$

 
 
$
697,623

 
$

 
 
$



Impairment of Proved Properties

AMR and the AMH Debtors filed for bankruptcy protection in September 2019. As a result, our ability to incur the levels of spending necessary to continue to develop our properties has been significantly restricted. This has negatively impacted our future drilling plans and our expectations regarding production levels from our properties. As a result, we conducted an assessment of impairment and recognized impairment expense for our proved properties at September 30, 2019. In determining the amount of impairment for our properties, we utilized future expected cash flows from those properties (a Level 3 input), discounted at a market participant rate to estimate fair value.

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 the unused office space within three buildings but we were unable to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

Impairment of Midstream Property and Equipment

The majority of the oil, gas and produced water volumes gathered and processed by our Midstream segment arise from our Upstream segment. Due to the factors mentioned above, the volumes gathered and processed by our Midstream segment are expected to decline, resulting in reduced throughput and value of our Midstream assets. Accordingly, we conducted an assessment of impairment and recognized impairment expense for our Midstream property and equipment at September 30, 2019. In determining the amount of impairment for our Midstream property and equipment, we utilized future expected cash flows from those assets (a Level 3 input), discounted at a market participant rate to estimate fair value.

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

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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, although we may sublease our unused office lease space in the future.
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 September 30, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.3 years and the weighted-average discount rate applied was 14.5%.

Lease Costs
(in thousands)
 
Three Months Ended
September 30, 2019
 
Nine Months Ended September 30, 2019
Operating lease cost
 
$
668

 
$
2,343

Variable lease cost
 
210

 
1,059

Short-term lease cost
 
422

 
4,072

Total lease cost
 
$
1,300

 
$
7,474

 
 
 
 
 
Reported in:
 
 
 
 
Lease operating expense
 
$
378

 
$
4,016

General and administrative expense
 
922

 
3,458

Total lease cost
 
$
1,300

 
$
7,474





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Remaining Operating Lease Liability Payments as of September 30, 2019
Fiscal year
 
(in thousands)
Remainder of 2019
 
$
649

2020
 
2,614

2021
 
2,581

2022
 
2,713

2023
 
2,718

Thereafter
 
12,647

Total lease payments
 
23,922

Less: imputed interest
 
(10,409
)
Less: reclassification to liabilities subject to compromise
 
(1,996
)
Present value of operating lease liabilities not subject to compromise
 
$
11,517

 
 
 
Current portion of operating lease liabilities
 
$
736

Operating lease liabilities, net of current portion
 
10,781

Present value of operating lease liabilities not subject to compromise
 
$
11,517



As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

NOTE 6 - EARNINGS (LOSS) PER SHARE

The following table reflects the net income attributable to common stockholders and earnings per share for the periods indicated based on a weighted average number of common shares outstanding for the period:

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Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018

(in thousands, except shares and per share data)
Net income (loss) attributable to AMR Class A common stockholders
$
(342,187
)
 
$
6,973

 
 
$
(348,349
)
 
$
(12,957
)
Effect of dilutive Class C securities:
 
 
 
 
 
 
 
 
Net loss attributable to noncontrolling interests assumed to be redeemed for Class A Common Stock, net of tax

 
4,869

 
 

 
(5,227
)
Net income (loss) attributable to AMR Class A common stockholders after assumed redemption
$
(342,187
)
 
$
11,842

 
 
$
(348,349
)
 
$
(18,184
)

 
 
 
 
 
 
 
 
Weighted average Class A common shares outstanding (Basic)
182,716,273

 
178,078,132

 
 
181,250,401

 
174,364,715

Effect of dilutive securities:
 
 
 
 
 

 
 
Class A shares assumed issued to holders of noncontrolling interests upon redemption

 
132,428,358

 
 

 
59,006,903

Restricted stock and stock options

 
31,342

 
 

 

Weighted average common shares outstanding (Diluted)
182,716,273

 
310,537,832

 
 
181,250,401

 
233,371,618


 
 
 
 
 
 
 
 
Income (loss) per common share attributable to AMR common stockholders:
 
 
 
 
 
 
 
 
Basic
$
(1.87
)
 
$
0.04

 
 
$
(1.92
)
 
$
(0.07
)
Diluted
$
(1.87
)
 
$
0.04

 
 
$
(1.92
)
 
$
(0.08
)


NOTE 7 — SUPPLEMENTAL CASH FLOW INFORMATION

Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Supplemental cash flow information:
 
 
 
 
 
 
Cash paid for interest
$
35,866

 
$
24,950

 
 
$
1,145

Cash paid for income taxes, net of refunds
706

 
1,573

 
 

Non-cash investing and financing activities:
 
 
 
 
 
 
Increase in asset retirement obligations
831

 
4,652

 
 

Increase (decrease) in accruals or payables for capital expenditures
(147,756
)
 
41,069

 
 
4,896

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

 
966,384

 
 

Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other

 
(905
)
 
 

Increase in accounts receivable for sale of assets

 
(524
)
 
 



We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.  
໿


NOTE 8 — RECEIVABLES

Accounts Receivable
(in thousands)
September 30, 2019
 
December 31, 2018
Production and processing sales and fees
$
40,348

 
$
51,004

Joint interest billings
17,411

 
18,147

Pooling interest (1)
8,974

 
18,786

Allowance for doubtful accounts
(347
)
 
(95
)
Total accounts receivable, net
$
66,386

 
$
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)
September 30, 2019
 
December 31, 2018
Related party receivables
$
12,135

 
$
12,375

Allowance for doubtful accounts
(12,135
)
 
(9,034
)
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




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At December 31, 2018, we had a receivable 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 the third quarter 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 High Mesa

(in thousands)
September 30, 2019
High Mesa related party receivable at December 31, 2018
$
10,066

Additions
832

Payments
(1,073
)
High Mesa related party receivable at September 30, 2019
9,825

Allowance for uncollectibility(1)
(9,825
)
Balance at September 30, 2019, net
$

_________________
(1)
$9.0 million of the allowance was recognized during the 2018 Successor Period.

Our management services agreement with HMI (“the High Mesa Agreement”) was terminated 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 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 High Mesa Agreement. As of September 30, 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. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.8 million and $9.0 million as of September 30, 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 September 30, 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 September 30, 2019 and December 31, 2018.

In addition, we have a 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.  HMI disputes its obligations under the note. As of September 30, 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. 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 will address any potential conflicts of interest with respect to this matter.


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NOTE 9 — PROPERTY AND EQUIPMENT

(in thousands)
September 30, 2019
 
December 31, 2018
Oil and gas properties
 
 
 
Unproved properties
$
816,858

 
$
816,282

Accumulated impairment of unproved properties
(782,287
)
 
(742,065
)
Unproved properties, net
34,571

 
74,217

Proved oil and gas properties
2,240,337

 
2,110,346

Accumulated depletion and impairment
(1,909,565
)
 
(1,421,226
)
Proved oil and gas properties, net
330,772

 
689,120

Total oil and gas properties, net
365,343

 
763,337

Other property and equipment
 
 
 
Land
5,600

 
5,600

Fresh water wells
27,373

 
27,366

Produced water disposal system
108,422

 
104,498

Gas processing plant and gathering lines
413,793

 
380,470

Office furniture, equipment and vehicles
3,687

 
3,703

Accumulated depreciation and impairment
(392,300
)
 
(77,368
)
Other property and equipment, net
166,575

 
444,269

Total property and equipment, net
$
531,918

 
$
1,207,606



During the third quarter, we recognized a charge of $11.2 million as exploration expense to reduce unproved properties for third and fourth quarter 2019 expirations of leased acreage. As a significant portion of these expirations were located in Major County, we determined that, given limited availability of development capital, our intent was to continue to let leased acreage in Major County expire in the normal course, thus abandoning development of Major County.  As such, we recorded an additional charge as exploration expense for all remaining acreage in Major County totaling $28.8 million

Depletion and Depreciation Expense

 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Oil and gas properties depletion
$
32,652

 
$
44,593

 
 
$
100,617

 
$
81,452

 
 
$
11,021

Midstream depreciation
3,589

 
2,099

 
 
10,313

 
5,231

 
 

Other property and equipment depreciation
508

 
1,030

 
 
1,257

 
1,616

 
 
609

Total depletion and depreciation
$
36,749

 
$
47,722

 
 
$
112,187

 
$
88,299

 
 
$
11,630




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NOTE 10 — DISCONTINUED OPERATIONS (Predecessor)

The results of operations of the non-STACK oil and gas assets and related liabilities distributed to High Mesa immediately prior to the Business Combination and presented as discontinued operations during the Predecessor Period were as follows:


Predecessor
(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 expense
 
Interest expense
(103
)
Loss from discontinued operations, net of tax
$
(7,746
)


Predecessor
(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
)



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NOTE 11 — DERIVATIVES  

During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts 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. As of September 30, 2019, we held no open derivative positions.

The following summarizes the fair value and classification of our derivatives:

 
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 table summarizes the effect of our derivatives in our statements of operations (in thousands):
 
Successor
 
 
Predecessor
Derivatives not designated as hedges
Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Gain (loss) on derivatives -
 
 
 
 
 
 
 
 
 
 
 
Oil
$
522

 
$
(12,339
)
 
 
$
(16,013
)
 
$
(62,995
)
 
 
$
4,796

Natural gas
(901
)
 
1,127

 
 
4,269

 
553

 
 
1,867

Total gain (loss) on derivatives
$
(379
)
 
$
(11,212
)
 
 
$
(11,744
)
 
$
(62,442
)
 
 
$
6,663



Other receivables at December 31, 2018 included $1.3 million of derivative positions settled in January 2019.



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NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 
໿
(in thousands)
September 30, 2019
 
December 31, 2018
Accounts payable
$
22,406

 
$
20,422

 
 
 
 
Accruals for capital expenditures
4,879

 
139,904

Revenue and royalties payable
28,417

 
50,241

Accruals for operating expenses
18,324

 
21,830

Accrued interest
16,512

 
2,477

Derivative settlements
511

 
109

Other
1,137

 
12,456

Total accrued liabilities
69,780

 
227,017

Less: liabilities subject to compromise
(31,185
)
 

Accounts payable and accrued liabilities
$
61,001

 
$
247,439



NOTE 13 — ASSET RETIREMENT OBLIGATIONS 

Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Balance, beginning of period
$
11,552

 
$

 
 
$
10,469

Liabilities assumed in Business Combination

 
5,998

 
 

Liabilities incurred
831

 
1,689

 
 

Liabilities settled
(180
)
 
(1,249
)
 
 
(63
)
Liabilities transferred in sale of properties

 
(20
)
 
 

Revisions to estimates
19

 
3,562

 
 
63

Accretion expense
720

 
489

 
 
40

Balance, end of period
12,942

 
10,469

 
 
10,509

Less: current portion
74

 
1,300

 
 
33

Long-term portion
$
12,868

 
$
9,169

 
 
$
10,476



NOTE 14 — DEBT
໿
(in thousands)
September 30, 2019
 
December 31, 2018
Alta Mesa RBL
$
340,004

 
$
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
1,064,004

 
864,123

Less: liabilities subject to compromise
(500,000
)
 

Less: current portion
(564,004
)
 
(690,123
)
Long-term debt, net
$

 
$
174,000


Alta Mesa RBL
In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million, leaving no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their

25

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ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated above, AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.

The Alta Mesa RBL has two covenants that were tested quarterly:

a ratio of Alta Mesa’s current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and
a ratio of Alta Mesa’s consolidated debt to its consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0
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.
KFM Credit Facility
The KFM Credit Facility, as amended, provides for an aggregate committed borrowing capacity of $300.0 million.
There are two maintenance covenants under the KFM Credit Facility that are tested quarterly:
a ratio of KFM’s total debt to its consolidated adjusted EBITDA of not greater than 4.5 to 1.0, (which increases to 4.75 after KFM exceeds consolidated EBITDA of $75.0 million) for any 4 quarter period; and
a minimum interest coverage ratio of KFM’s adjusted EBITDA to interest expense of not less than 2.5 to 1.0.
The KFM Credit Facility also limits KFM to holding no more than $15.0 million in cash and limits its ability to amend affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.
In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. At October 31, 2019, undrawn borrowing capacity under the KFM Credit Facility totaled $76.0 million.
2024 Notes
We have estimated the fair value of the 2024 Notes to be $85.7 million at September 30, 2019, which is based on their most recent trading values, which is a Level 1 determination.
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.
Scheduled Maturities of Debt
Fiscal year
 
(in thousands)
2023
 
$
564,004

2024
 
500,000


 
$
1,064,004




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Based upon our going concern conclusions, the default associated with Alta Mesa’s bankruptcy filing and KFM’s projected covenant violations, we believe that all of our indebtedness should be reported as current liabilities despite their scheduled maturities shown above.

NOTE 15 — COMMITMENTS AND CONTINGENCIES 
There have been no material developments during the first nine months of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K except as discussed below. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.

At December 31, 2018, Alta Mesa had an $18.3 million letter of credit issued to provide financial assurance for a multi-year obligation. During 2019, this letter of credit was reduced by $2.4 million in the ordinary course. In November 2019, the transportation company demanded full payment of $15.9 million for non-payment of $0.5 million in prepetition claims. This amount was paid by the administrative agent of the Alta Mesa RBL, but we believe the claims arising under the transportation contract were stayed by Alta Mesa’s bankruptcy filing. A demand letter has been sent to the transportation company to return the excess payment above the prepetition claims. It is unclear if or when this matter will be resolved.

NOTE 16 — 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 is 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.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.
ARM has also provided us with strategic advice, execution and reporting services with respect to our derivatives activities.
 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Revenue marketed by ARM on our behalf
$
7,643

 
$
114,109

 
 
$
117,003

 
$
234,850

 
 
$
28,757

 

 

 
 

 

 
 

Marketing and management fees paid to ARM
$
272

 
$

 
 
$
1,483

 
$

 
 
$

Fees paid to ARM for services relating to our derivatives
56

 
216

 
 
467

 
499

 
 
66

Total fees paid to ARM
$
328

 
$
216

 
 
$
1,950

 
$
499

 
 
$
66



Receivables from ARM for sales on our behalf were $5.4 million and $43.8 million as of September 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

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 and marketing firms are readily available. 

NOTE 17 EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense recognized was as follows:
 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
September 30, 2019
 
Three Months Ended
September 30, 2018
 
 
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Stock options
$
859

 
$
1,782

 
 
$
2,758

 
$
4,569

 
 
$

Restricted stock awards
600

 
1,271

 
 
2,068

 
3,764

 
 

Performance-based restricted stock units
47

 
(2,449
)
 
 
199

 

 
 

Total compensation expense
$
1,506

 
$
604

 
 
$
5,025

 
$
8,333

 
 
$



Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year is based on achievement of annual company-specific performance goals and obligations applicable to

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each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the units issued in each tranche. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.

The performance targets for the 2019 tranche of performance-based restricted stock units were established in March 2019 and 572,990 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment and our assessment of the probability of attainment of the established metrics.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

NOTE 18 — RELATED PARTY TRANSACTIONS 

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $132,000 and $28,000 for the period February 9, 2018 through September 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s 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, $1,089,000 and $29,000 during the nine months ended September 30, 2019, the period February 9, 2018 through September 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.

David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $242,000, $264,000, 67,000, for the nine months ended September 30, 2019, the period February 9, 2018 through September 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs 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, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of September 30, 2019, 61 joint wells have been drilled or spudded. At September 30, 2019 and December 31, 2018, $2.6 million and $9.8 million, respectively of revenue 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 condensed consolidated balance sheets. At September 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. 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.

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NOTE 19 — BUSINESS SEGMENT INFORMATION


Three Months Ended September 30, 2019
(in thousands)
Exploration &
Production
 
Midstream
 
Corporate and Eliminations
 
Total
Revenue
 
 
 
 
 
 
 
Oil
$
84,010

 
$

 
$

 
$
84,010

Natural gas
10,788

 

 

 
10,788

Natural gas liquids
8,333

 

 

 
8,333

Sales of gathered production

 
8,387

 

 
8,387

Midstream revenue

 
20,326

 
(14,444
)
 
5,882

Segment sales revenue
103,131

 
28,713

 
(14,444
)
 
117,400

Other revenue
302

 
5,720

 
(3,879
)
 
2,143

Operating revenue
103,433

 
34,433

 
(18,323
)
 
119,543

Loss on sale of assets

 
(106
)
 

 
(106
)
Loss on derivatives
(379
)
 

 

 
(379
)
Total revenue
103,054

 
34,327

 
(18,323
)
 
119,058

Operating expenses
 
 
 
 
 
 
 
Lease operating
18,071

 

 
(3,879
)
 
14,192

Transportation, processing and marketing
17,561

 
3,062

 
(14,444
)
 
6,179

Midstream operating

 
6,621

 

 
6,621

Cost of sales for purchased gathered production

 
7,656

 

 
7,656

Production taxes
4,673

 

 

 
4,673

Workovers
757

 
26

 

 
783

Exploration
40,847

 

 

 
40,847

Depreciation, depletion and amortization
33,407

 
3,592

 

 
36,999

Impairment of assets
387,721

 
303,402

 

 
691,123

General and administrative
14,852

 
8,075

 
5,065

 
27,992

Total operating expenses
517,889

 
332,434

 
(13,258
)
 
837,065

Operating income
(414,835
)
 
(298,107
)
 
(5,065
)
 
(718,007
)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(12,233
)
 
(2,912
)
 

 
(15,145
)
Interest income
45

 
6

 
18

 
69

Equity in earnings of unconsolidated subsidiaries

 
(29
)
 

 
(29
)
Reorganization items, net
22,905

 

 
(438
)
 
22,467

Total other income (expense)
10,717

 
(2,935
)
 
(420
)
 
7,362

Income (loss) from continuing operations before income taxes
(404,118
)
 
(301,042
)
 
(5,485
)
 
(710,645
)
 
 
 
 
 
 
 
 
Interest expense
12,233

 
2,912

 

 
15,145

Depreciation, depletion and amortization
33,407

 
3,592

 

 
36,999

Loss on unrealized hedges
7,112

 

 

 
7,112

Impairment of assets
387,721

 
303,402

 

 
691,123

Equity-based compensation
1,396

 
110

 

 
1,506

Exploration
40,847

 

 

 
40,847

Severance costs
418

 
178

 

 
596

Strategic costs
3,647

 
1,397

 
3,397

 
8,441

Provision for uncollectible related party receivable

 
2,310

 

 
2,310

Reorganization items, net
(22,905
)
 

 
438

 
(22,467
)
Adjusted EBITDAX
$
59,758

 
$
12,859

 
$
(1,650
)
 
$
70,967

 
 
 
 
 
 
 
 
Capital expenditures
$
63,571

 
$
4,381

 
$

 
$
67,952



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Table of Contents



Three Months Ended September 30, 2018
(in thousands)
Exploration &
Production
 
Midstream
 
Corporate and Eliminations
 
Total
Revenue
 
 
 
 
 
 
 
Oil
$
107,253

 
$

 
$

 
$
107,253

Natural gas
11,959

 

 

 
11,959

Natural gas liquids
13,880

 

 

 
13,880

Sales of gathered production

 
27,405

 
(18,276
)
 
9,129

Midstream revenue

 
20,775

 
(12,973
)
 
7,802

Segment sales revenue
133,092

 
48,180

 
(31,249
)
 
150,023

Other revenue
1,011

 

 

 
1,011

Operating revenue
134,103

 
48,180

 
(31,249
)
 
151,034

Loss on sale of assets
(18
)
 

 

 
(18
)
Loss on derivatives
(11,212
)
 

 

 
(11,212
)
Total revenue
122,873

 
48,180

 
(31,249
)
 
139,804

Operating expenses
 
 
 
 
 
 
 
Lease operating
16,351

 

 

 
16,351

Transportation, processing and marketing
15,820

 
2,334

 
(12,973
)
 
5,181

Midstream operating

 
4,507

 

 
4,507

Cost of sales for purchased gathered production

 
27,737

 
(18,276
)
 
9,461

Production taxes
6,311

 

 

 
6,311

Workovers
1,065

 

 

 
1,065

Exploration
1,029

 

 

 
1,029

Depreciation, depletion and amortization
45,849

 
7,254

 

 
53,103

Impairment of assets

 

 

 

General and administrative
7,918

 
3,423

 
561

 
11,902

Total operating expenses
94,343

 
45,255

 
(30,688
)
 
108,910

Operating income
28,530

 
2,925

 
(561
)
 
30,894

Other income (expense)
 
 
 
 
 
 
 
Interest expense
(11,008
)
 
(1,339
)
 

 
(12,347
)
Interest income
322

 
3

 
32

 
357

Total other income (expense)
(10,686
)
 
(1,336
)
 
32

 
(11,990
)
Income (loss) from continuing operations before income taxes
17,844

 
1,589

 
(529
)
 
18,904

 
 
 
 
 
 
 
 
Interest expense
11,008

 
1,339

 

 
12,347

Depreciation, depletion and amortization
45,849

 
7,254

 

 
53,103

Gain on unrealized hedges
(2,655
)
 

 

 
(2,655
)
Equity-based compensation
326

 
278

 

 
604

Exploration
1,029

 

 

 
1,029

Adjusted EBITDAX
$
73,401

 
$
10,460

 
$
(529
)
 
$
83,332

 
 
 
 
 
 
 
 
Capital expenditures
$
169,967

 
$
13,047

 
$

 
$
183,014


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Table of Contents



Nine Months Ended September 30, 2019
(in thousands)
Exploration &
Production
 
Midstream
 
Corporate and Eliminations
 
Total
Revenue
 
 
 
 
 
 
 
Oil
$
261,041

 
$

 
$

 
$
261,041

Natural gas
41,622

 

 

 
41,622

Natural gas liquids
29,800

 

 

 
29,800

Sales of gathered production

 
28,386

 

 
28,386

Midstream revenue

 
64,814

 
(45,228
)
 
19,586

Segment sales revenue
332,463

 
93,200

 
(45,228
)
 
380,435

Other revenue
1,200

 
20,094

 
(13,052
)
 
8,242

Operating revenue
333,663

 
113,294

 
(58,280
)
 
388,677

Gain (loss) on sale of assets
1,483

 
(106
)
 

 
1,377

Loss on derivatives
(11,744
)
 

 

 
(11,744
)
Total revenue
323,402

 
113,188

 
(58,280
)
 
378,310

Operating expenses
 
 
 
 
 
 
 
Lease operating
62,302

 

 
(13,052
)
 
49,250

Transportation, processing and marketing
54,936

 
7,911

 
(45,228
)
 
17,619

Midstream operating

 
19,292

 

 
19,292

Cost of sales for purchased gathered production

 
26,071

 

 
26,071

Production taxes
15,273

 

 

 
15,273

Workovers
1,366

 
537

 

 
1,903

Exploration
46,190

 

 

 
46,190

Depreciation, depletion and amortization
102,586

 
10,321

 

 
112,907

Impairment of assets
394,221

 
303,402

 

 
697,623

General and administrative
51,522

 
21,462

 
11,698

 
84,682

Total operating expenses
728,396

 
388,996

 
(46,582
)
 
1,070,810

Operating income
(404,994
)
 
(275,808
)
 
(11,698
)
 
(692,500
)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(39,134
)
 
(8,226
)
 

 
(47,360
)
Interest income
126

 
16

 
57

 
199

Equity in earnings of unconsolidated subsidiaries

 
713

 

 
713

Reorganization items, net
22,905

 

 
(438
)
 
22,467

Total other income (expense)
(16,103
)
 
(7,497
)
 
(381
)
 
(23,981
)
Income (loss) from continuing operations before income taxes
(421,097
)
 
(283,305
)
 
(12,079
)
 
(716,481
)
 
 
 
 
 
 
 
 
Interest expense
39,134

 
8,226

 

 
47,360

Depreciation, depletion and amortization
102,586

 
10,321

 

 
112,907

Loss on unrealized hedges
19,386

 

 

 
19,386

Impairment of assets
394,221

 
303,402

 

 
697,623

Equity-based compensation
4,453

 
572

 

 
5,025

Exploration
46,190

 

 

 
46,190

Severance costs
5,002

 
2,162

 

 
7,164

Strategic costs
6,489

 
1,397

 
3,397

 
11,283

Provision for uncollectible related party receivable

 
2,310

 

 
2,310

Reorganization items, net
(22,905
)
 

 
438

 
(22,467
)
Adjusted EBITDAX
$
173,459

 
$
45,085

 
$
(8,244
)
 
$
210,300

 
 
 
 
 
 
 
 
Equity method investment at period end
$

 
$
1,813

 
$

 
$
1,813

Capital expenditures
243,709

 
72,185

 

 
315,894

Total assets at period end
552,744

 
156,225

 
(11,902
)
 
697,067


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Table of Contents



February 9, 2018 Through September 30, 2018
(in thousands)
Exploration &
Production
 
Midstream
 
Corporate and Eliminations
 
Total
Revenue
 
 
 
 
 
 
 
Oil
$
222,822

 
$

 
$

 
$
222,822

Natural gas
25,149

 

 

 
25,149

Natural gas liquids
28,835

 

 

 
28,835

Sales of gathered production

 
59,039

 
(37,113
)
 
21,926

Midstream revenue

 
44,446

 
(26,567
)
 
17,879

Segment sales revenue
276,806

 
103,485

 
(63,680
)
 
316,611

Other revenue
3,795

 

 

 
3,795

Operating revenue
280,601

 
103,485

 
(63,680
)
 
320,406

Gain on sale of assets
5,058

 

 

 
5,058

Loss on derivatives
(62,442
)
 

 

 
(62,442
)
Total revenue
223,217

 
103,485

 
(63,680
)
 
263,022

Operating expenses
 
 
 
 
 
 
 
Lease operating
37,347

 

 

 
37,347

Transportation, processing and marketing
32,608

 
7,895

 
(26,567
)
 
13,936

Midstream operating

 
8,407

 

 
8,407

Cost of sales for purchased gathered production

 
59,285

 
(37,113
)
 
22,172

Production taxes
10,332

 

 

 
10,332

Workovers
2,643

 

 

 
2,643

Exploration
10,697

 

 

 
10,697

Depreciation, depletion and amortization
83,557

 
19,159

 

 
102,716

Impairment of assets

 

 

 

General and administrative
60,383

 
9,736

 
1,991

 
72,110

Total operating expenses
237,567

 
104,482

 
(61,689
)
 
280,360

Operating income
(14,350
)
 
(997
)
 
(1,991
)
 
(17,338
)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(26,565
)
 
(3,005
)
 

 
(29,570
)
Interest income
1,688

 
3

 
36

 
1,727

Total other income (expense)
(24,877
)
 
(3,002
)
 
36

 
(27,843
)
Income (loss) from continuing operations before income taxes
(39,227
)
 
(3,999
)
 
(1,955
)
 
(45,181
)
 
 
 
 
 
 
 
 
Interest expense
26,565

 
3,005

 

 
29,570

Depreciation, depletion and amortization
83,557

 
19,159

 

 
102,716

Loss on unrealized hedges
30,241

 

 

 
30,241

Equity-based compensation
6,714

 
784

 
835

 
8,333

Exploration
10,697

 

 

 
10,697

Business Combination
23,717

 

 

 
23,717

Adjusted EBITDAX
$
142,264

 
$
18,949

 
$
(1,120
)
 
$
160,093

 
 
 
 
 
 
 
 
Capital expenditures
$
489,009

 
$
34,636

 
$

 
$
523,645

Total assets at period end
2,957,284

 
1,447,913

 
7,862

 
4,413,059



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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this 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 impact of the Chapter 11 proceedings on our business, 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 in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the sections titled “Risk Factors” in this Quarterly Report and in our 2018 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an independent exploration and production company focused on the acquisition, development, exploration and production 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 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. 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 generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are vital to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.

As of September 30, 2019, we have a highly contiguous position of approximately 128,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and southeastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. 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 well level production that we expected. 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. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense. We operated 2 rigs after restarting the program, however, as a result of our bankruptcy filing in September 2019, we have ceased all development activities, unless or until such activities are approved by the Court or until our bankruptcy can be resolved.

We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries to meet our financial obligations. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date.  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 presentation reflects Alta Mesa as the “Predecessor” for the period January 1, 2018 to February 8, 2018. The Company, including the consolidated results of Alta Mesa and KFM, is the “Successor” for periods since February 9, 2018.

Accordingly, for purposes of explaining our segment results, we have presented the results of our Upstream and Midstream segments for the three months ended September 30, 2019, in comparison to the results for the three months ended September 30, 2018, and the results for the nine months ended September 30, 2019, in comparison to (i) the results of the Upstream and Midstream segments for the period February 9, 2018 through September 30, 2018, and (ii) the results of Alta Mesa for the Predecessor Period. As KFM was acquired on February 9, 2018, its results are not included in the Predecessor Period.

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We distributed our non-STACK oil and gas assets and liabilities to High Mesa in connection with the closing of the Business Combination. We report the non-STACK oil and gas assets and liabilities as discontinued operations during the Predecessor Period.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control.  The success of our business is 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; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, gas and NGL prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa RBL.

Key performance indicators

During 2019, our board of directors established the following operating measures as key performance indicators for executive management compensation and the Company as a whole:

Production;
General and administrative costs (excluding strategic costs);
Lease operating expense;
Well drilling and completion costs; and
Adjusted EBITDA or EBITDAX.

We will focus on measuring our performance against baseline and prior year comparable periods during this and future filings.
The Company’s management believes Adjusted EBITDA for our Midstream segment and Adjusted EBITDAX for our Upstream segment 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 businesses that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDA and Adjusted EBITDAX should not be considered as alternatives to our 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.

Going concern

On September 11, 2019, the Debtors filed voluntary Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code. Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries, Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC, (together the “non-Debtors”) are not in bankruptcy or otherwise part of the Chapter 11 cases at this time.

On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors have been authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The current cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral until November 21, 2019 on the terms and conditions agreed by the AMH Debtors and their creditors (including the lenders under the Alta Mesa RBL) as set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain other milestones related to sale of the Debtor assets. The continued access to the cash collateral will also be dependent

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upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.

The Debtors are in a marketing process to sell their assets along with KFM’s midstream assets. On October 11, 2019, the Bankruptcy Court entered an order approving, among other things, proposed bidding procedures and the dates for an auction, a hearing to approve the sale or sales of assets, and related dates and deadlines. The auction is scheduled to occur on January 8, 2020 and the sale hearing is scheduled to occur on January 10, 2020. Both of the scheduled dates are subject to postponement.

Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the crude oil and gas gathering agreements are subject to rescission as the products of breaches of fiduciary duty, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, 2019.

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.

Delisting from Stock Exchange

As a result of our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively. 

Derivatives

The objective of our hedging program was to produce, over time, relative revenue stability. However, both settlements and fair value changes in our derivatives have historically significantly impacted our short-term results of operations. During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts 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.

Impairments

During the three months ended September 30, 2019, we determined that the reduction in our borrowing base under the Alta Mesa RBL and our filing for bankruptcy protection were indicators of potential impairment of our tangible long-lived assets due to the negative impact they would have on our future development plans, revenue and cash flows. Accordingly, we compared our estimated future undiscounted cash flows to the carrying value of our oil and gas properties and our Midstream property and equipment, which indicated that they were not fully recoverable. Based on a determination of the fair value of those assets utilizing estimates of discounted cash flows and market values, we recognized impairments of (i) $387.7 million for our proved oil and gas properties and (ii) $303.4 million for our Midstream property and equipment.


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We also impaired certain operating lease right-of-use assets during the nine months ended September 30, 2019 totaling $6.5 million based on our expected inability to recover the full cash cost of our lease obligations through subleasing certain unused office space in three buildings located in Houston, Texas and Oklahoma City, Oklahoma.

Late in the 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, along with other factors, resulted in impairment charges of $2.0 billion to our oil and gas properties and $1.2 billion to our Midstream segment goodwill, tangible and intangible assets during the quarter ended December 31, 2018. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place.
 
Factors affecting future performance
The primary factors affecting our production levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. Our development program was established to overcome this natural decline. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. We expect that our ability to add reserves through drilling and other development techniques will be significantly curtailed as a result of our bankruptcy filing, which will have an adverse effect on our revenue growth and our operating cash flow.


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RESULTS OF OPERATIONS

For the Three Months Ended September 30, 2019 (“Third Quarter 2019”) Compared to the Three Months Ended September 30, 2018 (“Third Quarter 2018”).
Upstream Segment Results

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:
(in thousands, except per unit data)
Third Quarter 2019
 
Third Quarter 2018
Net production:
 
 
 
Oil (Mbbls)
1,516

 
1,539

Natural gas (MMcf)
6,416

 
5,116

NGLs (Mbbls)
642

 
685

Total (MBoe)
3,227

 
3,077


 
 
 
Average net daily production volumes:
 
 
 
Oil (Mbblsd)
16.5

 
16.7

Natural gas (MMcfd)
69.7

 
55.6

NGLs (Mbblsd)
7.0

 
7.4

Total (MBoed)
35.1

 
33.4


 
 
 
Average sales prices:
 
 
 
Oil (per bbl)
$
55.40

 
$
69.67

Effect of realized derivatives settlements (per bbl)
3.25

 
(8.88
)
Oil, after hedging (per bbl)
$
58.65

 
$
60.79

Percentage of unhedged realized oil price to NYMEX oil price
98
%
 
100
%

 
 
 
Natural gas (per Mcf)
$
1.68

 
$
2.34

Effect of realized derivatives settlements (per Mcf)
0.28

 
(0.04
)
Natural gas, after hedging (per Mcf)
$
1.96

 
$
2.30


 
 
 
NGLs (per bbl)
$
12.98

 
$
20.26

Effect of realized derivatives settlements (per bbl)

 

NGLs, after hedging (per bbl)
$
12.98

 
$
20.26

 
 
 
 
Revenue
 
 
 
Oil sales
$
84,010

 
$
107,253

Natural gas sales
10,788

 
11,959

NGL sales
8,333

 
13,880

Total sales revenue
$
103,131

 
$
133,092

 
 
 
 
Loss on sale of assets
$

 
$
(18
)
Oil sales for the third quarter 2019 decreased due primarily to lower average sales prices before hedging as well as decreased oil production. Natural gas sales for the third quarter 2019 decreased due primarily to lower average sales prices before hedging, partially offset by increased gas production. NGL sales for the third quarter 2019 decreased due to both lower average sales prices before hedging and decreased volumes.

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Derivatives
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Gain (loss) on derivatives:
 
 
 
Oil
$
4,922

 
$
(13,663
)
Natural gas
1,811

 
(204
)
Total realized gains (losses)
6,733

 
(13,867
)
Unrealized gains (losses)
(7,112
)
 
2,655

Total gain (loss) on derivatives
$
(379
)
 
$
(11,212
)
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 quarter. The decrease in derivative losses results from more price stability during 2019.
During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts 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.

Operating Expenses
(in thousands, except per unit data)
Third Quarter 2019
 
Third Quarter 2018
Operating expenses:
 
 
 
Lease operating
$
18,071

 
$
16,351

Transportation and marketing
17,561

 
15,820

Production taxes
4,673

 
6,311

Workovers
757

 
1,065

Exploration
40,847

 
1,029

Depreciation, depletion and amortization
33,407

 
45,849

Impairment of assets
387,721

 

General and administrative
14,852

 
7,918

Total operating expense
$
517,889

 
$
94,343

 
 
 
 
Operating expenses per BOE:
 
 
 
Lease operating
$
5.60

 
$
5.31

Transportation and marketing
5.44

 
5.14

Production taxes
1.45

 
2.05

Workovers
0.23

 
0.35

Depreciation, depletion and amortization
10.35

 
14.90

Lease operating expense for the third quarter 2019 increased due to higher gas production and the impact of additional costs after the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.
Transportation and marketing expense for the third quarter 2019 increased due to higher gas volumes. The amount for the third quarter 2019 also reflects a more significant expense due to an increase in committed capacity.
Production taxes for the third quarter 2019 decreased due to the decrease in gross production revenue from the third quarter 2018.

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Workovers are associated with maintenance and other efforts to increase production. During the third quarter 2019, these costs decreased due to less workover projects being undertaken.
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Exploration expense:
 
 
 
Geological and geophysical costs
$
192

 
$
947

Other exploration expense, including expired leases
40,655

 
149

ARO settlements in excess of recorded liabilities

 
(67
)
Total exploration expense
$
40,847

 
$
1,029

Exploration expense during the third quarter 2019 increased largely due to an increase in expired and expiring leases, primarily for those in Major County, Oklahoma.
Depreciation, depletion and amortization was lower on a per BOE basis during the third quarter 2019 largely due to the amount of impairment taken on our oil and gas properties during the fourth quarter of 2018, which reduced the depletable base.
Impairment of assets reflects the recognition of $387.7 million for impairment of proved properties during the third quarter 2019. No similar impairments were recognized during the third quarter 2018.
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
General and administrative expense:
 
 
 
Employee-related costs
$
3,695

 
$
3,577

Equity-based compensation
1,396

 
326

Professional fees
3,526

 
2,215

Strategic costs
3,647

 

Severance costs
418

 

Information technology
1,151

 
967

Operating leases
793

 
815

Provision for uncollectible receivables

 
2

Other
226

 
16

Total general and administrative expense
$
14,852

 
$
7,918

General and administrative expenses during the third quarter 2019 increased due mainly to costs for legal and financial strategic advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties. As of the Petition Date, all professional fees incurred from that date forward and directly related to the bankruptcy, are reported as Reorganization items, net.



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Table of Contents

Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:

(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Income (loss) from continuing operations before income taxes
$
(404,118
)
 
$
17,844

 
 
 
 
Interest expense
12,233

 
11,008

Depreciation, depletion and amortization
33,407

 
45,849

Exploration
40,847

 
1,029

Loss (gain) on unrealized hedges
7,112

 
(2,655
)
Impairment of assets
387,721

 

Equity-based compensation
1,396

 
326

Severance costs
418

 

Strategic costs
3,647

 

Reorganization items, net
(22,905
)
 

Adjusted EBITDAX
$
59,758

 
$
73,401

Other (Income) Expense
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Alta Mesa RBL
$
5,234

 
$
457

2024 Notes
7,765

 
9,844

Bond premium amortization
(970
)
 
(1,230
)
Deferred financing cost amortization
56

 
70

Other
148

 
1,867

Total interest expense
12,233

 
11,008

Interest income
(45
)
 
(322
)
Reorganization items, net
(22,905
)
 

Total other (income) expense, net
$
(10,717
)
 
$
10,686

Interest expense for the third quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL and higher recent interest rates. No interest expense on the 2024 Notes has been recognized since our filing for bankruptcy due to our expectations that such post-bankruptcy interest will not be paid. In addition, the remaining bond premium associated with the 2024 Notes and deferred financing costs associated with the Alta Mesa RBL were written off. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.
Reorganization items, net
(in thousands)
Three Months Ended
September 30, 2019
Unamortized deferred financing fees and premiums
$
(24,748
)
Terminated contracts
(394
)
Legal and other professional advisory fees
2,237

Reorganization items, net
$
(22,905
)


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Table of Contents


Midstream Segment Results

Revenue
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Produced water disposal fees
$
5,720

 
$

Midstream revenue
20,326

 
20,775

Sales of gathered production
8,387

 
27,405

Total Midstream revenue
$
34,433

 
$
48,180

 
 
 
 
KFM produced water gathering volumes (Mbbls)
5,799

 

KFM crude oil volumes (Mbbls)
12

 
760

KFM gas volumes (MMcf)
12,309

 
10,710


Produced water disposal fees resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.

Sales of gathered production decreased due to a substantial decrease in the sales price of NGLs.


Operating Expenses
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Midstream operating
$
6,621

 
$
4,507

Cost of sales for purchased gathered production
7,656

 
27,737

Transportation and processing
3,062

 
2,334

Workovers
26

 

Depreciation and amortization
3,592

 
7,254

Impairment of assets
303,402

 

General and administrative
8,075

 
3,423

Total operating expenses
$
332,434

 
$
45,255


Midstream operating expense increased due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018.

Cost of sales for purchased gathered production decreased due to the sales decline to third parties for sales of gathered production.

Transportation and processing expense increased as a result of an increase in gas throughput volumes.

Depreciation and amortization decreased due to $5.2 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018.

Impairment of assets totaling $303.4 million was recognized during the third quarter 2019 to adjust the segment’s property and equipment to fair value as the future expected cash flows were not sufficient to provide for recovery of the carrying value of the assets. No similar impairment was recognized during the third quarter 2018.

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Table of Contents

(in thousands)
Third Quarter 2019
 
Third Quarter 2018
General and administrative expenses:
 
 
 
Employee-related costs
$
3,155

 
$
1,669

Equity-based compensation
110

 
278

Professional fees
409

 
431

Strategic costs
1,397

 

Severance costs
178

 

Information technology
119

 
108

Operating leases
131

 
110

Provision for uncollectible receivables
2,310

 

Other
266

 
827

Total general and administrative expense
$
8,075

 
$
3,423


General and administrative expense increased during the third quarter 2019 as a result of increased employee-related costs allocable to KFM, and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility.

Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted Midstream EBITDA:
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
Income (loss) from continuing operations before income taxes
$
(301,042
)
 
$
1,589

 
 
 
 
Interest expense
2,912

 
1,339

Depreciation and amortization
3,592

 
7,254

Impairment of assets
303,402

 

Equity-based compensation
110

 
278

Severance costs
178

 

Strategic costs
1,397

 

Provision for uncollectible related party receivable
2,310

 

Adjusted Midstream EBITDA
$
12,859

 
$
10,460


Other (Income) Expense
(in thousands)
Third Quarter 2019
 
Third Quarter 2018
KFM Credit Facility
$
2,723

 
$
998

Deferred financing cost amortization
117

 
117

Other
72

 
224

Total interest expense
2,912

 
1,339

Interest income
(6
)
 
(3
)
Equity in earnings of unconsolidated subsidiaries
29

 

Total other (income) expense, net
$
2,935

 
$
1,336


Interest expense for the third quarter 2019 increased primarily due to increased levels of borrowings under the KFM Credit Facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.

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Table of Contents

For the Nine Months Ended September 30, 2019 (“2019 Period”) Compared to the Periods February 9, 2018 Through September 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor)
The tables included below set forth financial information for the Successor Periods and Predecessor Period, which 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 Successor Period from February 9, 2018 through September 30, 2018 and Predecessor Period from January 1, 2018 through February 8, 2018 as the “2018 Period”.

Upstream Segment Results

Revenue

Successor
 
 
Predecessor
(in thousands, except per unit data)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Net production:
 
 
 
 
 
 
Oil (Mbbl)
4,680

 
3,313

 
 
494

Natural gas (MMcf)
18,530

 
11,308

 
 
1,609

NGLs (Mbbl)
2,256

 
1,462

 
 
151

Total (MBoe)
10,024

 
6,660

 
 
914


 
 
 
 
 
 
Average net daily production volumes:
 
 
 
 
 
 
Oil (Mbbld)
17.1

 
14.2

 
 
12.7

Natural gas (MMcfd)
67.9

 
48.3

 
 
41.2

NGLs (Mbbld)
8.3

 
6.2

 
 
3.9

Total (MBoed)
36.7

 
28.5

 
 
23.4


 
 
 
 
 
 
Average sales prices:
 
 
 
 
 
 
Oil (per bbl)
$
55.77

 
$
67.26

 
 
$
62.68

Effect of realized derivatives settlements (per bbl)
1.47

 
(10.02
)
 
 
(6.44
)
Oil, after hedging (per bbl)
$
57.24

 
$
57.24

 
 
$
56.24

Percentage of unhedged realized oil price to NYMEX oil price
98
%
 
100
%
 
 
99
%

 
 
 
 
 
 
Natural gas (per Mcf)
$
2.25

 
$
2.22

 
 
$
2.66

Effect of realized derivatives settlements (per Mcf)
0.04

 
0.03

 
 
0.94

Natural gas, after hedging (per Mcf)
$
2.29

 
$
2.25

 
 
$
3.60


 
 
 
 
 
 
NGLs (per bbl)
$
13.21

 
$
19.72

 
 
$
26.41

Effect of realized derivatives settlements (per bbl)

 

 
 

NGLs, after hedging (per bbl)
$
13.21

 
$
19.72

 
 
$
26.41

 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
Oil sales
$
261,041

 
$
222,822

 
 
$
30,972

Natural gas sales
41,622

 
25,149

 
 
4,276

NGL sales
29,800

 
28,835

 
 
4,000

Total sales
$
332,463

 
$
276,806

 
 
$
39,248

 
 
 
 
 
 
 
Gain on sale of assets
$
1,483

 
$
5,058

 
 
$
840



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Table of Contents

Oil sales for the 2019 Period increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination. Natural gas sales for the 2019 Period increased primarily due to an increase in production as a result of the extensive development program conducted following the Business Combination.

Gain (loss) on sale of assets for the 2019 Period included a gain from the sale of seismic data totaling $1.5 million compared to a similar gain of $5.9 million during the 2018 Period.

Derivatives

Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Gain (loss) on derivatives:
 
 
 
 
 
 
Oil
$
6,858

 
$
(32,555
)
 
 
$
(3,819
)
Natural gas
784

 
354

 
 
1,523

Total realized gains (losses)
7,642

 
(32,201
)
 
 
(2,296
)
Unrealized gains (losses)
(19,386
)
 
(30,241
)
 
 
8,959

Total gain (loss) on derivatives
$
(11,744
)
 
$
(62,442
)
 
 
$
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 nine month period.
The reduced derivative losses in the 2019 Period are due to greater price stability in 2019, whereas in the 2018 Period commodity prices improved over that time period.
During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts 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.


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Table of Contents

Operating Expenses


Successor
 
 
Predecessor
(in thousands, except per unit data)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Operating expenses:
 
 
 
 
 
 
Lease operating
$
62,302

 
$
37,347

 
 
$
4,408

Transportation and marketing
54,936

 
32,608

 
 
3,725

Production taxes
15,273

 
10,332

 
 
953

Workovers
1,366

 
2,643

 
 
423

Exploration
46,190

 
10,697

 
 
7,003

Depreciation, depletion and amortization
102,586

 
83,557

 
 
11,670

Impairment of assets
394,221

 

 
 

General and administrative
51,522

 
60,383

 
 
21,234

Total operating expense
$
728,396

 
$
237,567

 
 
$
49,416

 
 
 
 
 
 
 
Operating expenses per BOE:
 
 
 
 
 
 
Lease operating
$
6.22

 
$
5.61

 
 
$
4.82

Transportation and marketing
5.48

 
4.90

 
 
4.08

Production taxes
1.52

 
1.55

 
 
1.04

Workovers
0.14

 
0.40

 
 
0.46

Depreciation, depletion and amortization
10.23

 
12.55

 
 
12.77


Lease operating expense for the 2019 Period increased due to higher gas production and the impact of additional costs after the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.

Transportation and marketing expense for the 2019 Period increased primarily due to higher volumes. 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 2019 period also reflects a more significant expense due to an increase in committed capacity which went unused.

Production taxes for the 2019 Period increased primarily due to the increase in gross production revenue 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 are associated with maintenance and other efforts to increase production. During the 2019 Period, these costs decreased due to less workover projects being undertaken to reduce costs.


Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Exploration expense:
 
 
 
 
 
 
Geological and geophysical costs
$
870

 
$
2,537

 
 
$
2,440

Other exploration expense, including expired leases
45,259

 
7,561

 
 
4,504

ARO settlements in excess of recorded liabilities
61

 
599

 
 
59

Total exploration expense
$
46,190

 
$
10,697

 
 
$
7,003



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Exploration expense for the 2019 Period increased largely due to an increase in expired and expiring leases, primarily for those in Major County, Oklahoma. Geological and geophysical costs are down due to headcount reductions.

Impairment of assets reflects the recognition of $394.2 million for impairment of proved properties and right-of-use assets during the 2019 Period. No similar impairments were recognized during the 2018 Period.

Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
General and administrative expense:
 
 
 
 
 
 
Employee-related costs
$
18,652

 
$
16,223

 
 
$
1,032

Equity-based compensation
4,453

 
6,714

 
 

Professional fees
8,479

 
7,749

 
 
1,019

Strategic costs
6,489

 

 
 

Business Combination

 
23,717

 
 
17,040

Severance costs
5,002

 

 
 

Information technology
3,131

 
3,616

 
 

Operating leases
3,110

 
2,301

 
 
208

Provision for uncollectible receivables
1,139

 

 
 

Other
1,067

 
63

 
 
1,935

Total general and administrative expense
$
51,522

 
$
60,383

 
 
$
21,234


General and administrative expense for the 2019 Period decreased compared to the 2018 Period primarily due to nonrecurring Business Combination costs and other professional fees incurred in the 2018 Period for advisors helping to value and integrate the acquired business. General and administrative expense during the 2019 Period also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties, as well as severance costs associated with a reduction in force. As of the Petition Date, all professional fees incurred from that date forward and directly related to the bankruptcy, are reported as Reorganization items, net.


Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:


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Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Loss from continuing operations before income taxes
$
(421,097
)
 
$
(39,227
)
 
 
$
(7,116
)
 
 
 
 
 
 
 
Interest expense
39,134

 
26,565

 
 
5,511

Depreciation, depletion and amortization
102,586

 
83,557

 
 
11,670

Exploration
46,190

 
10,697

 
 
7,003

Loss (gain) on unrealized hedges
19,386

 
30,241

 
 
(8,959
)
Impairment of assets
394,221

 

 
 

Equity-based compensation
4,453

 
6,714

 
 

Severance costs
5,002

 

 
 

Strategic costs
6,489

 

 
 

Business Combination

 
23,717

 
 
17,040

Reorganization items, net
(22,905
)
 

 
 

Adjusted EBITDAX
$
173,459

 
$
142,264

 
 
$
25,149


Other (Income) Expense


Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Alta Mesa RBL
$
14,017

 
$
709

 
 
$
815

2024 Notes
27,453

 
26,250

 
 
3,281

Bond premium amortization
(3,432
)
 
(3,281
)
 
 

Deferred financing cost amortization
195

 
150

 
 
171

Other
901

 
2,737

 
 
1,244

Total interest expense
39,134

 
26,565

 
 
5,511

Interest income
(126
)
 
(1,688
)
 
 
(172
)
Reorganization items, net
(22,905
)
 

 
 

Total other (income) expense, net
$
16,103

 
$
24,877

 
 
$
5,339

Interest expense for the 2019 Period increased primarily due to increased levels of borrowing under the Alta Mesa RBL. No interest expense on the 2024 Notes has been recognized since our filing for bankruptcy due to our expectations that such post-bankruptcy interest will not be paid. In addition, the remaining bond premium associated with the 2024 Notes and deferred financing costs associated with the Alta Mesa RBL were written off. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

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Reorganization items, net
(in thousands)
Nine Months Ended
September 30, 2019
Unamortized deferred financing fees and premiums
$
(24,748
)
Terminated contracts
(394
)
Legal and other professional advisory fees
2,237

Reorganization items, net
$
(22,905
)

Midstream Segment Results

Revenue
(in thousands)
Nine Months Ended September 30, 2019
 
February 9, 2018
Through
September 30, 2018
Produced water disposal fees
$
20,094

 
$

Midstream revenue
64,814

 
44,446

Sales of gathered production
28,386

 
59,039

Total Midstream revenue
$
113,294

 
$
103,485

 
 
 
 
KFM produced water gathering volumes (Mbbls)
20,421

 

KFM crude oil volumes (Mbbls)
1,049

 
1,193

KFM gas volumes (MMcf)
37,409

 
23,654


Produced water disposal fees resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.

Midstream revenue increased due to increased oil and gas gathered volumes and the impact of a second cryogenic processing train being commissioned in mid-2018.

Sales of gathered production decreased due to a substantial decrease in the sales price of NGLs.

Operating Expenses
(in thousands)
Nine Months Ended September 30, 2019
 
February 9, 2018
Through
September 30, 2018
Midstream operating
$
19,292

 
$
8,407

Cost of sales for purchased gathered production
26,071

 
59,285

Transportation and processing
7,911

 
7,895

Workovers
537

 

Depreciation and amortization
10,321

 
19,159

Impairment of assets
303,402

 

General and administrative
21,462

 
9,736

Total operating expenses
$
388,996

 
$
104,482



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Midstream operating expense for the 2019 Period increased compared to the 2018 Period due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes, which led to higher compressor-related costs.

Cost of sales for purchased gathered production decreased in the 2019 Period due to the sales decline to third parties for sales of gathered production.

Depreciation and amortization during the 2018 Period included $13.9 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was partially offset by an increase of million in depreciation of tangible assets during the 2019 Period due to capital spending since September 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018.

Impairment of assets totaling $303.4 million was recognized during the 2019 Period to adjust the segment’s property and equipment to fair value as the future expected cash flows were not sufficient to provide for recovery of the carrying value of the assets. No similar impairment was recognized during the 2018 Period.
(in thousands)
Nine Months Ended September 30, 2019
 
February 9, 2018
Through
September 30, 2018
General and administrative expenses:
 
 
 
Employee-related costs
$
10,878

 
$
5,682

Equity-based compensation
572

 
784

Professional fees
2,254

 
963

Strategic costs
1,397

 
10

Severance costs
2,162

 

Information technology
245

 
112

Operating leases
348

 
149

Provision for uncollectible receivable
2,310

 

Other
1,296

 
2,036

Total general and administrative expense
$
21,462

 
$
9,736


General and administrative expense increased during the 2019 Period as a result of increased employee-related costs allocable to KFM 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 the 2019 Period, 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 income (loss) from continuing operations before income taxes to Adjusted Midstream EBITDA:

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(in thousands)
Nine Months Ended September 30, 2019
 
February 9, 2018
Through
September 30, 2018
Loss from continuing operations before income taxes
$
(283,305
)
 
$
(3,999
)
 
 
 
 
Interest expense
8,226

 
3,005

Depreciation and amortization
10,321

 
19,159

Impairment of assets
303,402

 

Equity-based compensation
572

 
784

Severance costs
2,162

 

Strategic costs
1,397

 

Provision for uncollectible related party receivable
2,310

 

Adjusted Midstream EBITDA
$
45,085

 
$
18,949


Other (Income) Expense
(in thousands)
Nine Months Ended September 30, 2019
 
February 9, 2018
Through
September 30, 2018
KFM Credit Facility
$
7,534

 
$
1,320

Predecessor revolving credit facility

 
980

Deferred financing cost amortization
346

 
189

Other
346

 
516

Total interest expense
8,226

 
3,005

Interest income
(16
)
 
(3
)
Equity in earnings of unconsolidated subsidiaries
(713
)
 

Total other (income) expense, net
$
7,497

 
$
3,002


Interest expense for the 2019 Period increased primarily due to increased levels of borrowings particularly under the KFM Credit Facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.

Equity in earnings of unconsolidated subsidiaries represents our share of the net income during the 2019 Period associated with our 50% ownership in the Cimarron pipeline (“Cimarron”). Our investment in Cimarron is accounted for under the equity method.

LIQUIDITY AND CAPITAL RESOURCES

Our principal requirements for capital during 2019 have been to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and derivatives. During 2019, our main sources of liquidity and capital resources came from operating cash flow and borrowings under the Alta Mesa RBL and KFM Credit Facility.

In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million leaving no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated above, AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments.


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AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. In September 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. The Administrative Agent and the lenders have reserved their right to pursue any remedies available to them, including charging the default rate of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral. Although the Administrative Agent and the lenders have not taken any such actions, KFM will not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact AMR’s and KFM’s ability to meet all financial obligations as they come due and KFM’s ability to make distributions to AMR that otherwise may have been permitted. As a result of Alta Mesa’s bankruptcy and the limitations imposed under a Bankruptcy Court approved cash collateral agreement and alleged defaults under the KFM Credit Facility, AMR’s only remaining source of liquidity is through non-debtor subsidiary SRII Opco. At October 31, 2019, SRII Opco had cash on hand of $5.5 million. We also believe that KFM will fail to meet the maintenance covenants of the KFM Credit Facility as early as the first quarter of 2020, which would prevent any further borrowings.

During September 2019, we ceased all development activities, other than any that may be prospectively approved by the Court or until our bankruptcy cases can be resolved. The abandonment of planned development activities, particularly with respect to bringing new wells onto production, will likely reduce our production levels, revenue and cash flow, and may result in the expiry of certain leases. Under the terms and conditions of the cash collateral order approved by the Bankruptcy Court and corresponding budget, we are not able to operate any drilling rigs during the fourth quarter of 2019, although we had certain capital spending to finish drilling wells that were in process at the time of our bankruptcy filing. We expect our fourth quarter 2019 capital spending to be substantially less than before the bankruptcy filing.

We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries to meet our financial obligations.

During November 2019 we reached an agreement with our co-investor in Cimarron Express Pipeline, LLC (“CEPL”) to begin the process of redeeming their 50% ownership.  As a result, we expect to begin consolidating Cimarron following that redemption, which will provide additional cash resources of approximately $7 million and additional rights-of-way.   The value of the net assets to be consolidated beginning in November 2019 approximates the value of the equity method investment as of September 30, 2019. Once CEPL is consolidated, the cash it holds will generally be available to KFM for its use to meet operating costs, but due to the alleged default under the KFM Credit Facility, it cannot be distributed to AMR for its expenses or other uses.

At December 31, 2018, Alta Mesa had an $18.3 million letter of credit issued to provide financial assurance for a multi-year obligation. During 2019, this letter of credit was reduced by $2.4 million in the ordinary course. In November 2019, the transportation company demanded full payment of $15.9 million for non-payment of $0.5 million in prepetition claims. This amount was paid by the administrative agent of the Alta Mesa RBL, but we believe the claims arising under the transportation contract were stayed by Alta Mesa’s bankruptcy filing. A demand letter has been sent to the transportation company to return the excess payment above the prepetition claims. It is unclear if or when this matter will be resolved.

As we execute our business strategy, we will monitor the capital resources available to meet future financial obligations and planned capital expenditures. We cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all.

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Cash Flow Analysis
 
Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Cash from operating activities
$
129,452

 
$
2,506

 
 
$
26,336

Cash from investing activities
(315,894
)
 
(282,048
)
 
 
(37,913
)
Cash from financing activities
228,863

 
312,211

 
 
16,932

Net increase in cash, cash equivalents and restricted cash
$
42,421

 
$
32,669

 
 
$
5,355


Cash flow from operating activities

During the 2019 Period, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense totaled $134.0 million compared to $101.6 million during the 2018 Period, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in 2018. Approximately $4.5 million of cash was used to increase working capital during the 2019 Period. During the 2018 Period, cash totaling $72.8 million was used to increase working capital primarily due to increases in trade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of the Business Combination.

Cash flow from investing activities
 
Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Cash provided by (used for)
 
 
 
 
 
 
Capital expenditures
$
(315,894
)
 
$
(523,645
)
 
 
$
(36,695
)
Acquisitions, net of cash acquired

 
(791,819
)
 
 
(1,218
)
Proceeds withdrawn from trust account

 
1,042,742

 
 

Investment in equity affiliate and other, net

 
(9,326
)
 
 

Cash from investing activities
$
(315,894
)
 
$
(282,048
)
 
 
$
(37,913
)

During the 2019 Period, capital expenditures included $147.8 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of the reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and our existing liquidity concerns. We ran as many as 9 rigs during the 2018 period but have averaged much closer to 2 rigs for the 2019 Period. As a result of our bankruptcy filing in September 2019, we have ceased all development activities, unless or until such activities are approved by the Court or until our bankruptcy can be resolved.


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Cash flow from financing activities
 
Successor
 
 
Predecessor
(in thousands)
Nine Months Ended
September 30, 2019
 
February 9, 2018
Through
September 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Cash provided by (used for)
 
 
 
 
 
 
Proceeds from long-term debt borrowings
$
238,500

 
$
162,500

 
 
$
60,000

Repayments of long-term debt
(9,496
)
 
(193,565
)
 
 
(43,000
)
Payment of taxes withheld on equity-based compensation awards
(141
)
 

 
 

Deferred financing costs paid

 
(3,716
)
 
 

Purchase and retirement of Class A common shares

 
(14,750
)
 
 

Proceeds from issuance of Class A shares

 
400,000

 
 

Repayment of sponsor note

 
(2,000
)
 
 

Repayment of deferred underwriting compensation

 
(36,225
)
 
 

Other

 
(33
)
 
 
(68)
Cash from financing activities
$
228,863

 
$
312,211

 
 
$
16,932


During the 2019 Period, our outstanding balances owed under the Alta Mesa RBL and KFM Credit Facility increased by $229.0 million from December 31, 2018, largely related to borrowings to fund our capital expenditures, including those expenditures incurred in 2018.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives in the future to manage or reduce market risk, but we do not plan to enter into derivatives for speculative purposes. We have not previously designated derivatives as hedges for accounting purposes.

Commodity Price Risk and Hedges

Our major market risk exposure is to prevailing prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have historically used derivatives to reduce our exposure to the risks of price changes. During September 2019, in connection with the Company’s restructuring efforts, we cancelled (prior to contract settlement date) all derivative contracts 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.

Counterparty and Customer Credit Risk 
 
Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production and midstream gathering and processing activities. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production, midstream services and other working interest owners is high. Because Alta Mesa filed for bankruptcy protection, KFM’s ability to collect fees from Alta Mesa for midstream services could be impaired. We cannot predict the likelihood, if any, that Alta Mesa’s bankruptcy filing could have on KFM’s operating cash flow.

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 is 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.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. For the nine months ended September 30, 2019, ARM marketed $117.0 million, or 30.1% of our operating revenue for the period.
 
Joint operations receivables arise from billings to entities that own interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rates

We are subject to interest rate risk under the Alta Mesa RBL and KFM Credit Facility. We currently have no open interest rate derivatives. A 100 basis point increase in interest rates would increase our annual interest expense for both facilities by approximately $5.6 million, based on the balances outstanding at September 30, 2019.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the 2019 Period.  Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses. 

Item 4. 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

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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.

As described further in our 2018 10-K, we concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”). Apart from the controls and procedures relating to accounting for business combinations, several of the material weaknesses in our ICFR continued to exist during the 2019 Period. These material weaknesses include:

establishment of formal policies and procedures;
ineffective monitoring activities that span the Company to ensure that internal controls processes are functioning properly;
ineffective controls over the financial statement close and disclosure process; and
over-reliance on and ineffective controls over access to and changes involving critical worksheets.

As noted in our 2018 10-K, KFM was excluded from management’s assessment of internal control over financial reporting as of December 31, 2018 but will be included in our assessment for 2019.

Changes in Internal Control Over Financial Reporting (ICFR)

While we have made progress in multiple areas to improve ICFR, management is continuing to implement the remediation plan described in our 2018 10-K and continues to work to make changes in controls and procedures in a manner consistent with the size, complexity and scale of operations subsequent to the Business Combination.

During the third quarter 2019, 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. Further remediation efforts are continuing to resolve other material weaknesses identified during the prior year and we anticipate additional testing of controls to occur during the fourth quarter of 2019.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes 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. There have been no significant changes during the 2019 Period to the matters described in Legal Proceedings in our 2018 10-K.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.

Litigation
As previously disclosed in our 2018 10-K, 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. On October 28, 2019, Mustang filed a motion asking the Bankruptcy Court to lift the automatic stay to allow the litigation to proceed in the District Court of Kingfisher County, Oklahoma.


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Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes during the 2019 Period to the risk factors described under Risk Factors in our 2018 10-K, except as described below.

The Debtors are subject to the risks and uncertainties associated with proceedings under Chapter 11 of title 11 of the Bankruptcy Code.
For the duration of our Chapter 11 proceedings, the Debtors’ operations and their ability to develop and execute their business plans, as well as continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:
the Debtors’ ability to develop, confirm and consummate a Chapter 11 plan, asset sale or alternative restructuring transaction;
the Debtors’ ability to obtain court approval with respect to motions filed in Chapter 11 proceedings from time to time;
the Debtors’ ability to continue utilizing their relationships with their suppliers, service providers, customers, employees and other third parties;
the Debtors’ ability to maintain contracts that are critical to their operations;
the Debtors’ ability to execute their business plans;
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with the Debtors;
the Debtors’ ability to access, and maintain access to, sufficient financing for the duration of the Chapter 11 proceedings;
the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for the Debtors to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 proceedings to a proceeding under Chapter 7 of the Bankruptcy Code; and
the actions and decisions of the Debtors’ creditors and other third parties who have interests in these Chapter 11 proceedings that may be inconsistent with the Debtors’ plans.

These risks and uncertainties could affect the Debtors’ business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect the Debtors’ relationships with suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect the operations and financial condition of the Debtors. Also, the Debtors need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit their ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that will occur during these Chapter 11 proceedings that may be inconsistent with the Debtors’ plans.

The AMH Debtors’ cash collateral order and termination events limit the AMH Debtors’ operating flexibility, and the occurrence of any termination event under the cash collateral order could have significant adverse consequences.
The cash collateral order requires the AMH Debtors to adhere to an agreed budget with the secured lenders holding an interest in such cash collateral, and it contains covenants and/or termination events that, among other things, restrict the AMH Debtors’ ability to take specific actions and, in the case of termination events, may be outside of the AMH Debtors’ control. The current cash collateral order expires November 21, 2019 and is subject to renewal for succeeding periods that require Bankruptcy Court approval which may not be granted. Additionally, the cash collateral order contains specified milestones and dates by which they must occur relating to a potential sale of all or substantially all of the AMH Debtors’ assets, and/or pursuit of a Chapter 11 plan of reorganization of the AMH Debtors, with which the AMH Debtors must comply. The AMH Debtors’ ability to comply with these timelines may be affected by events and circumstances outside of their control. Non-compliance with the cash collateral order could result in the AMH Debtors losing access to cash collateral and/or foreclosure by the AMH Debtors’ secured lenders on the AMH Debtors’ assets that serve as collateral for their loans, subject to the terms of the cash collateral order.

Operating under Bankruptcy Court protection for a long period of time may harm our business.
A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 proceedings continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our

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business operations. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 proceedings continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the Chapter 11 proceedings continue, the Debtors will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceedings. Although no such financing has been sought to date, the Chapter 11 proceedings may also require the Debtors to seek debtor-in-possession financing to fund operations. If the Debtors are unable to obtain such financing on favorable terms or at all, their chances of successfully reorganizing their business may be seriously jeopardized, the likelihood that the Debtors will be required to liquidate their assets may be enhanced, and, as a result, any securities in the Debtors could become further devalued or become worthless. In addition, the AMH Debtors’ access to cash that serves as collateral for Alta Mesa’s secured lenders depends on Alta Mesa’s ability to obtain the consent of such lenders to continued use of cash collateral or entry of a Bankruptcy Court order authorizing such use without consent of the lenders.

Under the cash collateral order, the AMH Debtors are required to suspend most of their capital spending program, which will result in delays in developing our resources and in bringing new production on line. This could adversely impact our operating cash flow.
   
Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, the Debtors’ operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

The Chapter 11 proceedings create substantial uncertainty regarding certain significant intercompany commercial and other relationships.
The Chapter 11 proceedings create substantial uncertainty regarding certain significant commercial and other relationships among us, the other Debtors and our other subsidiaries, including KFM. These relationships include oil and gas gathering agreements, a produced water gathering and disposal agreement and a tax receivable agreement, among others, which may be subject to review and some of which have been challenged in the Chapter 11 proceedings. On September 12, 2019, an adversary proceeding was commenced by certain of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis, and Harlan H. Chappelle (together, the “Defendants”), alleging, among other things, that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and non-Debtors KFM and its subsidiaries can be rejected by the Debtors, (ii) certain amendments to the crude oil and gas gathering agreements were constructive 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, which as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement 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 can therefore be rejected under the Bankruptcy Code. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants. On November 4, 2019, the plaintiff AMH Debtors provided notice of alleged events of default under the crude oil and gas gathering agreements and reserved their rights and remedies, including termination of those agreements. The plaintiff AMH Debtors have also submitted a motion to file a second amended complaint to include these events of default allegations. The litigation is set for trial on December 9, with summary judgment motions, if any, scheduled to be heard on November 22, 2019, and a pending motion to dismiss by Defendants KFM and Oklahoma Produced Water Solutions, LLC scheduled to be heard on November 21, 2019. The outcome of the litigation is unknown at this time. We are unable to estimate the outcome of such challenges or other claims arising out of the Chapter 11 proceedings, any resulting material losses, obligations or other liabilities or their possible material adverse effect on KFM’s or our other subsidiaries’ business, results of operations and financial condition.

The Debtors may not be able to obtain confirmation of a Chapter 11 plan of reorganization.
To emerge successfully from Bankruptcy Court protection as a viable entity, the Debtors must meet certain statutory requirements with respect to adequacy of disclosure for a Chapter 11 plan, solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation

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process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding a Chapter 11 plan.

The Debtors may not receive the requisite acceptances of constituencies in the Chapter 11 proceedings to confirm a Chapter 11 plan. Even if the requisite acceptances are received, the Bankruptcy Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims or subordinated or senior claims).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether the Debtors would be able to reorganize their business and what, if anything, holders of claims against the Debtors would ultimately receive with respect to their claims.

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.
We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 proceedings until we are able to emerge from our Chapter 11 proceedings.

The Debtors’ liquidity, including their ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) their ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) their ability to maintain adequate cash on hand, (iii) their ability to generate cash flow from operations, (iv) continued access to the liquidity in our non-bankrupt subsidiaries, (v) their ability to develop, confirm and consummate a Chapter 11 plan or other alternative sale or restructuring transaction, and (vi) the cost, duration and outcome of the Chapter 11 proceedings.

In addition, because some of our subsidiaries did not file for bankruptcy protection they may be required to retain professional service providers that are redundant to the Debtors’ advisors. These expanded costs could stress their ability to fund other revenue-generating costs.

As a result of the Chapter 11 proceedings, the Debtors’ financial results may be volatile and may not reflect historical trends.
During the Chapter 11 proceedings, the Debtors expect their financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact their financial results. As a result, the Debtors’ historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if the Debtors emerge from Chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to their operating plans pursuant to a plan of reorganization. The Debtors also may be required to adopt fresh start accounting, in which case their assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. The Debtors’ financial results after the application of fresh start accounting also may be different from historical trends.

The Debtors may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on their financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through the plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

The Debtors’ inability to pay service providers on a timely basis may have an adverse effect on their ability to secure their future services.

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The Debtor’s inability to satisfy their obligations to service providers on a timely basis may result in irreparable harm to relationships with them and their willingness to continue to do business with the Debtors in the future under acceptable terms. Certain of the Debtors’ service providers have recently filed, and other service providers in the future may file, liens on the Debtors’ assets in order to collect on debts incurred prior to the bankruptcy filing. In addition, the Debtors as well as KFM and its subsidiaries may be required to make advance payments for services, and some critical and/or uniquely qualified service providers may refuse to continue to do business with us, which would result in material adverse consequences to us.

We may experience increased levels of employee attrition as a result of the Chapter 11 proceedings.
As a result of the Chapter 11 proceedings, we may experience increased levels of employee attrition, and our employees likely will face considerable increase in workload, distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the duration of the Chapter 11 proceedings is limited by restrictions for incentive programs under the Bankruptcy Code and by the cash collateral order. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition and results of operations.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.
We can provide no assurance as to whether the Debtors will successfully reorganize and emerge from the Chapter 11 proceedings or, if they do successfully reorganize, as to when they would emerge from the Chapter 11 proceedings.
If the Bankruptcy Court finds that it would be in the best interest of the Debtors’ creditors and/or the Debtors best interest, the Bankruptcy Court may convert the anticipated Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to the Debtors’ creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner, (ii) additional administrative expenses that would be incurred in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Any Chapter 11 plan or other plan of reorganization that the Debtors may implement will be based in large part upon assumptions and analyses developed by the Debtors. If these assumptions and analyses prove to be incorrect, the plan may be unsuccessful in its execution.

Any Chapter 11 plan or other plan of reorganization that the Debtors may implement could affect both their capital structure and the ownership, structure and operation of their businesses and will reflect assumptions and analyses based on their experience and perception of historical trends, current conditions and expected future developments, as well as other factors that they consider appropriate under the circumstances. Whether actual future results and developments will be consistent with these expectations and assumptions depends on a number of factors, including but not limited to (i) the ability to substantially change the Debtors’ capital structure; (ii) the ability to obtain adequate liquidity and financing sources; (iii) the ability to maintain customers’ confidence in the Debtors’ viability as a continuing entity and to attract and retain sufficient business from them; (iv) the ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of these businesses.

In addition, any plan of reorganization will be premised upon financial projections, including with respect to revenues, EBITDA, EBITDAX, capital expenditures, debt service and cash flow. Financial projections are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial projections will not be accurate. In this case, the projections will be even more speculative than normal, because they may involve fundamental changes in the nature of the Debtors’ capital structure. Accordingly, the Debtors expect that their actual financial condition and results of operations will differ, perhaps materially, from what they have anticipated. Consequently, we can provide no assurance that the results or developments contemplated by any plan of reorganization the Debtors may implement will occur or, even if they do

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occur, that they will have the anticipated effects on the Debtors or their businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Even if a Chapter 11 plan of reorganization is consummated, the Debtors may not be able to achieve their stated goals and continue as a going concern.
Even if a Chapter 11 plan of reorganization is consummated, the Debtors may continue to face a number of risks, such as deterioration in commodity prices or other changes in economic conditions, changes in the industry, changes in demand for oil and gas and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve the stated goals.

In addition, at the outset of Chapter 11 proceedings, the Bankruptcy Code gives the debtors the exclusive right to propose the plan of reorganization and prohibits creditors, equity security holders and others from proposing a plan. The Debtors currently have the exclusive right to propose a plan of reorganization. If that right is terminated, however, or the exclusivity period expires, there could be a material adverse effect on their ability to achieve confirmation of a plan of reorganization in order to achieve their stated goals.

Furthermore, even if the Debtors’ debts are reduced or discharged through a plan of reorganization, they may need to raise additional funds through public or private debt or equity financing or other various means to fund their business after the completion of the Chapter 11 proceedings. The Debtors’ access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

The Debtors’ ability to continue as a going concern is dependent upon their ability to raise additional capital. As a result, they cannot give any assurance of their ability to continue as a going concern, even if a plan of reorganization is confirmed.

For the duration of the Chapter 11 proceedings, Alta Mesa may not be able to enter into commodity derivatives covering estimated future production on favorable terms or at all.
During the Chapter 11 proceedings, Alta Mesa’s ability to enter into new commodity derivatives covering estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges and the willingness for counterparties to transact with us. As a result, Alta Mesa may not be able to enter into additional commodity derivatives covering production in future periods on favorable terms or at all. If Alta Mesa cannot or chooses not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than competitors who engage in hedging arrangements. Alta Mesa’s inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

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.

In addition, 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.

On September 23, 2019, the lenders under the KFM Credit Facility provided notice of an alleged event of default arising as a result of certain liens upon KFM’s assets and reserved their rights and remedies thereunder, including charging the default rate

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of interest, declaring any of the outstanding debt thereunder due and payable or foreclosing on, or instituting foreclosure proceedings against, or liquidating any collateral.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.



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Item 6. Exhibits

Exhibit
Number
Description of Exhibit
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
10.1
10.2
10.3
31.1*
31.2*
32.1*
32.2*
101*
Interactive data files.
* filed herewith.


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

 
 
ALTA MESA RESOURCES, INC.
 
 
(Registrant)
 
 
 
 
By
/s/ John C. Regan
 
 
 
John C. Regan
 
 
 
Chief Financial Officer (Principal Financial Officer)
 
 
 
 
 
 
Dated
 November 12, 2019
 
 


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