0001518403-18-000014.txt : 20180815 0001518403-18-000014.hdr.sgml : 20180815 20180815085300 ACCESSION NUMBER: 0001518403-18-000014 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 87 CONFORMED PERIOD OF REPORT: 20180630 FILED AS OF DATE: 20180815 DATE AS OF CHANGE: 20180815 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Alta Mesa Holdings, LP CENTRAL INDEX KEY: 0001518403 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 203565150 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 333-173751 FILM NUMBER: 181019836 BUSINESS ADDRESS: STREET 1: 15021 KATY FREEWAY STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77094 BUSINESS PHONE: 281-530-0991 MAIL ADDRESS: STREET 1: 15021 KATY FREEWAY STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77094 10-Q 1 altms-063018x10q.htm 10-Q Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
_______________________________________
FORM 10-Q
_______________________________________
(Mark One)
x   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: June 30, 2018
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: 333-173751
_______________________________________
ALTA MESA HOLDINGS, LP
(Exact name of registrant as specified in its charter)
_______________________________________
Texas
20-3565150
(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
_______________________________________
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  x
(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant 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 would have been required to file such reports) as if it were subject to such filing requirements.)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files.)    Yes  x    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 definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer
¨
Accelerated filer
¨
Non-accelerated filer
x
(Do not check if smaller reporting company)
Smaller reporting company
¨
Emerging growth company
x
 
 
 
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  x
 




Table of Contents

໿


2


Glossary of Terms

Certain terms and abbreviations used in this Quarterly Report on Form 10-Q are defined as follows:
bbl -
Barrels
bbl/d -
Barrels per day
BOE -
Barrels of oil equivalent
Btu -
British thermal units
Completion -
The installation of permanent equipment for the production of oil and gas
EBITDA -
Earnings before interest, taxes, depreciation, depletion, amortization
EBITDAX -
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses
Mbbls -
One thousand barrels
Mbbls/d -
One thousand barrels per day
MBoe/d -
One thousand barrels of oil equivalent per day
Mcf -
One thousand cubic feet
Mcf/d -
One thousand cubic feet per day
MMBtu -
One million British thermal units
MMcf -
One million cubic feet
MMcf/d -
One million cubic feet per day
NYMEX -
New York Mercantile Exchange
NGLs -
Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline
Wellbore -
A hole that is drilled to aid in the exploration and recovery of natural resources including oil or natural gas
Working interest -
An interest in a mineral property that entitles the owner of that interest to all of the share of the mineral production from the property, usually subject to a royalty
VWAP -
Volume weighted average price


3


Cautionary Statement Regarding Forward-Looking Statements

The information in this 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 on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project”, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2017 Annual Report and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:
the benefits of the Business Combination;
the future financial performance of the combined company following the Business Combination;
our business strategy;
our reserve quantities and the present value of our reserves;
our estimated purchase price and purchase price allocations;
our exploration and drilling prospects, inventories, projects and programs;
our horizontal drilling, completion and production technology;
our ability to replace the reserves we produce through drilling and property acquisitions;
our financial strategy, liquidity and capital required for our development program;
future oil, and natural gas prices;
the supply and demand for natural gas, natural gas liquids, crude oil and midstream services;
the timing and amount of future production of oil and natural gas;
our hedging strategy and results;
the drilling and completion of wells, including statements about future horizontal drilling plans;
competition and government regulation;
our ability to obtain permits and governmental approvals;
changes in the Oklahoma forced pooling system;
pending legal and environmental matters;
our future drilling plans;
our marketing of oil, natural gas and natural gas liquids;
our leasehold or business acquisitions;
our costs of developing our properties;
our liquidity and access to capital;
our ability to hire, train or retain qualified personnel;
general economic conditions;
our future operating results, including initial production values and liquid yields in our type curve areas;
the costs, terms and availability of gathering, processing, fractionation and other midstream services; and
our plans, objectives, expectations and intentions contained in this report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in our 2017 Annual Report and in this report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and

4


price and cost assumptions made by reservoir engineers.  Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in the 2017 Annual Report or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report on Form 10-Q.



5


PART I — FINANCIAL INFORMATION


ITEM 1. Financial Statements


ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands) 
໿

Successor
 
 
Predecessor

June 30,
2018
 
 
December 31, 2017
ASSETS
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents
$
74,004

 
 
$
3,660

Restricted cash
1,022

 
 
1,269

Accounts receivable, net
104,668

 
 
76,161

Other receivables
1

 
 
1,388

Receivables due from affiliate
9,068

 
 

Receivables due from related party
10,333

 
 
790

Note receivable due from related party
1,609

 
 

Prepaid expenses and other current assets
3,834

 
 
2,932

Current assets — discontinued operations

 
 
5,195

Derivative financial instruments

 
 
216

Total current assets
204,539


 
91,611

PROPERTY AND EQUIPMENT
 
 
 
 
Oil and natural gas properties, successful efforts method, net
2,550,519

 
 
894,630

Other property and equipment, net
50,091

 
 
32,140

Total property and equipment, net
2,600,610


 
926,770

OTHER ASSETS
 
 
 
 
Deferred financing costs, net
1,285

 
 
1,787

Notes receivable due from related party
11,262

 
 
12,369

Deposits and other long-term assets
48

 
 
9,067

Non-current assets — discontinued operations

 
 
43,785

Derivative financial instruments

 
 
8

Total other assets
12,595


 
67,016

TOTAL ASSETS
$
2,817,744


 
$
1,085,397


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





6


 
Successor
 
 
Predecessor
 
June 30,
2018
 
 
December 31, 2017
LIABILITIES AND PARTNERS' CAPITAL
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Accounts payable and accrued liabilities
$
143,107

 
 
$
170,489

Accounts payable — affiliate
481

 
 
5,476

Advances from non-operators
6,283

 
 
5,502

Advances from related party
37,135

 
 
23,390

Asset retirement obligations
538

 
 
69

Current liabilities — discontinued operations

 
 
15,419

Derivative financial instruments
37,743

 
 
19,303

Total current liabilities
225,287

 
 
239,648

LONG-TERM LIABILITIES
 
 
 
 
Asset retirement obligations, net of current portion
6,439

 
 
10,400

Long-term debt, net
531,584

 
 
607,440

Noncurrent liabilities — discontinued operations

 
 
66,862

Derivative financial instruments
6,385

 
 
1,114

Other long-term liabilities
6

 
 
5,488

Total long-term liabilities
544,414

 
 
691,304

TOTAL LIABILITIES 
769,701

 
 
930,952

Commitments and Contingencies (Note 13)


 
 


PARTNERS' CAPITAL
2,048,043

 
 
154,445

TOTAL LIABILITIES AND PARTNERS' CAPITAL
$
2,817,744

 
 
$
1,085,397



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

7


ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(in thousands)
໿

Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Three
 
 
Three
 
February 9, 2018
 
 
January 1, 2018
 
Six

Months Ended
 
 
Months Ended
 
Through
 
 
Through
 
Months Ended

June 30, 2018
 
 
June 30, 2017
 
June 30, 2018
 
 
February 8, 2018
 
June 30, 2017
OPERATING REVENUES AND OTHER
 
 
 
 
 
 
 
 
 
 
 
Oil
$
75,291

 
 
$
42,348

 
$
115,569

 
 
$
30,972

 
$
89,288

Natural gas
7,980

 
 
10,642

 
13,190

 
 
4,276

 
20,233

Natural gas liquids
10,241

 
 
6,581

 
14,955

 
 
4,000

 
13,653

Other revenues
2,229

 
 
1,979

 
2,784

 
 
888

 
3,213

Total operating revenues
95,741

 
 
61,550

 
146,498


 
40,136



126,387

Gain (loss) on sale of assets and other
(63
)
 
 

 
5,916

 
 

 

Gain (loss) on derivative contracts
(29,219
)
 
 
18,250

 
(51,865
)
 
 
7,298

 
48,492

Total operating revenues and other
66,459

 
 
79,800

 
100,549


 
47,434



174,879

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
Lease operating expense
12,679

 
 
11,480

 
20,996

 
 
4,485

 
22,490

Marketing and transportation expense
11,206

 
 
6,510

 
16,788

 
 
3,725

 
12,172

Production taxes
2,606

 
 
1,184

 
4,021

 
 
953

 
2,450

Workover expense
333

 
 
1,102

 
1,578

 
 
423

 
1,690

Exploration expense
8,083

 
 
3,192

 
13,038

 
 
3,633

 
8,239

Depreciation, depletion, and amortization expense
26,509

 
 
20,110

 
37,445

 
 
11,784

 
39,088

Impairment expense

 
 

 

 
 

 
1,188

Accretion expense
161

 
 
30

 
263

 
 
39

 
126

General and administrative expense
17,811

 
 
8,293

 
49,270

 
 
24,352

 
18,029

Total operating expenses
79,388

 
 
51,901

 
143,399


 
49,394



105,472

INCOME (LOSS) FROM OPERATIONS
(12,929
)
 
 
27,899

 
(42,850
)
 
 
(1,960
)
 
69,407

OTHER INCOME (EXPENSE)
 
 
 
 
 
 
 
 
 
 
 
Interest expense
(10,361
)
 
 
(12,578
)
 
(15,557
)
 
 
(5,511
)
 
(24,620
)
Interest income and other
820

 
 
299

 
1,366

 
 
172

 
548

Total other income (expense), net
(9,541
)
 
 
(12,279
)
 
(14,191
)

 
(5,339
)

(24,072
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES
(22,470
)
 
 
15,620

 
(57,041
)
 
 
(7,299
)
 
45,335

Provision for state income taxes
7

 
 

 
7

 
 

 
285

INCOME (LOSS) FROM CONTINUING OPERATIONS
(22,477
)
 
 
15,620

 
(57,048
)

 
(7,299
)


45,050

LOSS FROM DISCONTINUED OPERATIONS, NET OF STATE INCOME TAX

 
 
(30,934
)
 

 
 
(7,593
)
 
(35,449
)
NET INCOME (LOSS)
$
(22,477
)
 
 
$
(15,314
)
 
$
(57,048
)

 
$
(14,892
)


$
9,601




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

8


ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)
(in thousands)
໿

Predecessor
BALANCE, DECEMBER 31, 2017
$
154,445

DISTRIBUTION OF NON-STACK ASSETS (NET LIABILITY)
33,102

NET LOSS
(14,892
)
BALANCE, FEBRUARY 8, 2018
$
172,655


Successor
BALANCE, FEBRUARY 9, 2018
$
1,535,891

CAPITAL CONTRIBUTION
560,344

ISSUANCE OF ADDITIONAL ALTA MESA PURCHASE CONSIDERATION
9,467

EQUITY-BASED COMPENSATION
6,389

DISTRIBUTION
(7,000
)
NET LOSS
(57,048
)
BALANCE, JUNE 30, 2018
$
2,048,043



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

9


ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)
໿

Successor
 
 
Predecessor

February 9, 2018
 
 
January 1, 2018
 
Six
 
Through
 
 
Through
 
Months Ended
 
June 30, 2018
 
 
February 8, 2018
 
June 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
 
Net income (loss)
$
(57,048
)
 
 
$
(14,892
)
 
$
9,601

Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
 
 
 
 
 
 
Depreciation, depletion, and amortization expense
37,445

 
 
12,414

 
51,298

Impairment expense

 
 
5,560

 
29,124

Accretion expense
263

 
 
140

 
1,052

Amortization of deferred financing costs
80

 
 
171

 
1,456

Amortization of debt premium
(2,051
)
 
 

 

Equity-based compensation expense
6,389

 
 

 

Dry hole expense

 
 
(45
)
 
888

Expired leases
10,658

 
 
1,250

 
5,922

(Gain) loss on derivative contracts
51,865

 
 
(7,298
)
 
(48,492
)
Settlements of derivative contracts
(18,969
)
 
 
(1,661
)
 
254

Premium paid on derivative contracts

 
 

 
(520
)
Interest converted into debt

 
 
103

 
599

Interest on notes receivable due from related party
(417
)
 
 
(85
)
 
(406
)
Loss on sale of assets and other
63

 
 
1,923

 

Gain on acquisition of oil and gas properties

 
 

 
(1,626
)
Changes in assets and liabilities:
 
 
 
 
 
 
Accounts receivable
(2,923
)
 
 
(20,895
)
 
(11,478
)
Other receivables
1,221

 
 
(9,887
)
 
4,281

Receivables due from affiliate
(9,068
)
 
 

 

Receivables due from related party
(9,426
)
 
 
(117
)
 
(680
)
Prepaid expenses and other current and non-current assets
7,810

 
 
9,970

 
(11,644
)
Advances from related party
(10,371
)
 
 
24,116

 
(42,528
)
Settlement of asset retirement obligations
(806
)
 
 
(63
)
 
(977
)
Accounts payable — related party
(4,994
)
 
 

 

Accounts payable, accrued liabilities, and other liabilities
(45,210
)
 
 
25,815

 
7,655

NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES
(45,489
)

 
26,519


(6,221
)
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
Capital expenditures for property and equipment
(319,042
)
 
 
(38,096
)
 
(151,832
)
Acquisitions, net of cash acquired

 
 

 
(6,251
)
Proceeds from sale of assets and other, net
11,299

 
 

 

NET CASH USED IN INVESTING ACTIVITIES
(307,743
)
 
 
(38,096
)
 
(158,083
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
Proceeds from issuances of long-term debt

 
 
60,000

 
165,065

Repayments of long-term debt
(134,065
)
 
 
(43,000
)
 
(10,000
)
Additions to deferred financing costs
(1,366
)
 
 

 
(170
)
Capital distributions
(7,000
)
 
 
(68
)
 

Capital contributions
560,344

 
 

 
7,875

NET CASH PROVIDED BY FINANCING ACTIVITIES
417,913


 
16,932


162,770

NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
64,681

 
 
5,355

 
(1,534
)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period
10,345

 
 
4,990

 
7,618

CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period
$
75,026


 
$
10,345


$
6,084



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

10


ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 DESCRIPTION OF BUSINESS

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County ("STACK"). 

On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreement, dated August 16, 2017, with Alta Mesa Resources, Inc. (“AMR”) (formerly Silver Run Acquisition Corporation II), High Mesa Holdings, LP (the “AM Contributor”), High Mesa Holdings GP, LLC,  the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor (“AM Contribution Agreement”). Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement, dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor (the “KFM Contribution Agreement”); and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).

Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”), acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”

As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly-traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, were both controlled by High Mesa Inc. (“High Mesa”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.

In connection with the closing of the Business Combination, we distributed our non-STACK assets to the AM Contributor and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK.  

See to Note 5—Business Combination for further information related to the Business Combination.

NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report”).  As of June 30, 2018, our significant accounting policies are consistent with those discussed in Note 2 in the 2017 Annual Report, other than as noted below.

Basis of Presentation. As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree.  Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations, (“ASC 805”), our identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”).  Fair value adjustments related to the transaction have been pushed down to us resulting in our assets and liabilities being recorded at fair value as of the acquisition date.  As a result of the Transactions described above, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented.  The Successor period presented herein is for the three months ended June 30, 2018 and from February 9, 2018 to June 30, 2018 (“Successor Period”), (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three

11


months ended June 30, 2017 and the six months ended June 30, 2017 (“2017 Predecessor Period”), (collectively, the (“Predecessor Periods”).
As noted above, we distributed our non-STACK assets to the AM Contributor in connection with the closing of the Business Combination.  The distribution of our non-STACK assets and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements.  See Note 7 — Discontinued Operations (Predecessor) for further discussion.
Principles of Consolidation and Reporting. The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances.
The condensed consolidated financial statements included herein as of June 30, 2018, and for the three months ended June 30, 2018 (Successor) and the period from February 9, 2018 through June 30, 2018 (Successor), the period from January 1, 2018 through February 8, 2018 (Predecessor) and the three and six months ended June 30, 2017 (Predecessor), are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented.  The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2017, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report.  Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices.  The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. 
The Company’s statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.
Use of Estimates. The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other estimates are utilized to determine amounts related to oil and natural gas revenues, the value of oil and natural gas properties, the value of other property and equipment, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances.  We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Bond Premium on Senior Unsecured Notes. As a result of the pushdown accounting related to the Business Combination, the Company estimated the fair value of our $500 million senior unsecured notes at $533.6 million as of the acquisition date.  The amount in excess of the principal amount was recorded as a bond premium, which is being amortized as a reduction to interest expense. 

Equity-Based Compensation (Successor). The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options, restricted stock and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and restricted stock awards are valued using the market price of AMR’s common stock on the grant date. Compensation cost is recognized ratably over the

12


applicable vesting period.  See Note 16 – Equity-Based Compensation (Successor) for additional information regarding the Company’s equity based compensation.

Restricted Cash. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows (in thousands):
໿

Successor
 
 
Predecessor

June 30,
2018
 
 
December 31, 2017
Cash and cash equivalents
$
74,004

 
 
$
3,660

Restricted cash
1,022

 
 
1,269

Cash of discontinued operations

 
 
61

Total cash, cash equivalents and restricted cash
$
75,026


 
$
4,990


Recent Accounting Pronouncements Issued But Not Yet Adopted. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation.

ASU 2014-09, as amended, is effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act.

ASU 2014-09 allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company, we previously elected to use the extended transition period to defer implementation of the new standard until the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR, our parent company, is also an emerging growth company, but will cease to be an emerging growth company on December 31, 2018, which will require them to adopt ASU 2014-09 on December 31, 2018, with modified retroactive implementation as of January 1, 2018. Accordingly, we will also adopt ASU 2014-09, at the same time as our parent company.

We are in the process of assessing our contracts and evaluating the impact on our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09, as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant business practices and internal controls, if needed.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (except for short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases.  The standard will be effective for interim and annual periods beginning after December 15, 2018. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.

13



At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months.  The adoption is also expected to result in a change in the amount of lease expense recorded on our consolidated statement of operations, and additional disclosures.  As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018.  As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date.  

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. As an emerging growth company, we had elected to use the extended transition period to defer adoption of this standard until 2019.  However, our parent company will lose its emerging growth status, effective December 31, 2018.  Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. The adoption of this guidance will not impact our financial position or results of operations but could result in presentational changes in our consolidated statements of cash flows. 
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 used today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

Reclassifications. Certain prior year amounts have been reclassified to conform to the current year presentation.

NOTE 3 SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands):
໿

Successor
 
 
Predecessor

February 9, 2018
 
 
January 1, 2018
 
Six
 
Through
 
 
Through
 
Months Ended

June 30, 2018
 
 
February 8, 2018
 
June 30, 2017
Supplemental cash flow information:
 
 
 
 
 
 
Cash paid for interest
$
21,216

 
 
$
1,145

 
23,452

Cash paid for state income taxes
6

 
 

 

Non-cash investing and financing activities:
 
 
 
 
 
 
Change in asset retirement obligations
877

 
 

 
235

Asset retirement obligations assumed, purchased properties

 
 
 
 
89

Change in accruals or liabilities for capital expenditures
(27,646
)
 
 
4,712

 
37,494

Distribution of non-STACK assets (net liability)

 
 
33,102

 




14


NOTE 4 ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following (in thousands):

໿

Successor
 
 
Predecessor

June 30,
2018
 
 
December 31, 2017
Oil, natural gas and natural gas liquids sales
$
30,126

 
 
$
26,916

Joint interest billings
34,762

 
 
13,821

Pooling interest (1)
39,843

 
 
35,839

Allowance for doubtful accounts
(63
)
 
 
(415
)
Total accounts receivable, net
$
104,668


 
$
76,161

_________________
(1)
Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents costs of unbilled interests on wells which the Company incurred before the pooling process was completed.  Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.


NOTE 5 BUSINESS COMBINATION

As discussed in Note 1 - Description of Business, on February 9, 2018, we consummated the Transactions contemplated by the AM Contribution Agreement.

Pursuant to the AM Contribution Agreement, SRII Opco acquired (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP.  At the closing of the Transactions, the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco.  The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at closing.  

Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
໿
20-Day
VWAP
 
Earn-Out Consideration
$14.00
 
10,714,285 Common Units
$16.00
 
9,375,000 Common Units
$18.00
 
13,888,889 Common Units
$20.00
 
12,500,000 Common Units

The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.

AMR also contributed $560 million in net cash to us at the closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements.  We used a portion of the amount to repay all outstanding balance under the senior secured revolving credit facility described in Note 11 — Long Term Debt, Net.


15


Pursuant to the AM Contribution Agreement, AM Contributor delivered a final closing statement during the second quarter of 2018. Based on the final closing statement, the AM Contributor received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of AMR's Class C Common Stock.

The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination, and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that our assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by AMR, who was determined to be the accounting acquirer.  We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed.  Pursuant to ASC 805, finalization of the values is to be completed within one year of the Acquisition Date.

Preliminary Estimated Purchase Price

AMR’s preliminary estimated purchase price consideration for Alta Mesa was as follows (in thousands):
໿

February 9, 2018
(As initially reported)
 
Measurement Period Adjustment (1)
 
February 9, 2018 (As adjusted)
Preliminary Purchase Consideration: (2)
 
 
 
 
 
SRII Opco Common Units issued (3)
$
1,251,782

 
$
9,467

 
$
1,261,249

Estimated fair value of contingent earn-out purchase consideration (4)
284,109

 

 
284,109

Total purchase price consideration
$
1,535,891

 
$
9,467

 
$
1,545,358

_________________
(1)
The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor).
(2)
The preliminary purchase price consideration is for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP.  
(3)
At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity.
(4)
For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.


16


Preliminary Estimated Purchase Price Allocation

The following table summarizes the allocation of AMR’s preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in connection with the acquisition of Alta Mesa in the Business Combination. The allocation is as follows (in thousands):
໿

February 9, 2018
(As initially reported)
 
Measurement Period Adjustment (1)
 
February 9, 2018 (As adjusted)
Estimated Fair Value of Assets Acquired (2)
 
 
 
 
 
Cash, cash equivalents and short term restricted cash
$
10,345

 
$

 
$
10,345

Accounts receivable
101,745

 

 
101,745

Other receivables
1,222

 

 
1,222

Receivables due from related party
907

 

 
907

Prepaid expenses and other current assets
1,405

 

 
1,405

Derivative financial instruments
352

 

 
352

Property and equipment: (3)
 
 
 
 
 
Oil and natural gas properties, successful efforts
2,314,858

 
9,467

 
2,324,325

Other property and equipment, net
43,318

 

 
43,318

Notes receivable due from related party
12,454

 

 
12,454

Deposits and other long-term assets
10,286

 

 
10,286

Total fair value of assets acquired
2,496,892

 
9,467

 
2,506,359

Estimated Fair Value of Liabilities Assumed (2)
 
 
 
 
 
Accounts payable and accrued liabilities
210,867

 

 
210,867

Accounts payable — affiliate
5,476

 

 
5,476

Advances from non-operators
6,803

 

 
6,803

Advances from related party
47,506

 

 
47,506

Asset retirement obligations (3)
5,998

 

 
5,998

Derivative financial instruments
11,585

 

 
11,585

Long-term debt (4)
667,700

 

 
667,700

Other long-term liabilities
5,066

 

 
5,066

Total fair value of liabilities assumed
961,001

 

 
961,001

Total consideration and fair value
$
1,535,891

 
$
9,467

 
$
1,545,358

_________________
(1)
The measurement period adjustment is recognized in the reporting period in which the adjustment was determined and calculated as if the accounting had been completed at the acquisition date.
(2)
The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets.
(3)
The estimated fair values of oil and natural gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates.
(4)
Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and outstanding borrowings under the Eighth A&R credit facility (described in Note 11 — Long Term Debt, Net) of approximately $134.1 million as of the acquisition date.



17


NOTE 6 PROPERTY AND EQUIPMENT

Property and equipment consists of the following (in thousands):

Successor
 
 
Predecessor

June 30,
2018
 
 
December 31,
2017
OIL AND NATURAL GAS PROPERTIES
 
 
 
 
Unproved properties
$
891,787

 
 
$
84,590

Accumulated impairment of unproved properties

 
 

Unproved properties, net
891,787


 
84,590

Proved oil and natural gas properties
1,695,596

 
 
1,061,105

Accumulated depreciation, depletion, amortization and impairment
(36,864
)
 
 
(251,065
)
Proved oil and natural gas properties, net
1,658,732


 
810,040

TOTAL OIL AND NATURAL GAS PROPERTIES, net
2,550,519


 
894,630

OTHER PROPERTY AND EQUIPMENT
 
 
 
 
Land
5,059

 
 
2,912

Salt water disposal system
44,028

 
 
30,990

Office furniture and equipment, vehicles
1,585

 
 
20,008

Accumulated depreciation
(581
)
 
 
(21,770
)
OTHER PROPERTY AND EQUIPMENT, net
50,091


 
32,140

TOTAL PROPERTY AND EQUIPMENT, net
$
2,600,610


 
$
926,770


In conjunction with pushdown accounting, property and equipment was measured at fair value as of the acquisition date, which also impacted how value was assigned between the categories within property and equipment (see Note 5 – Business Combination for details).


NOTE 7 DISCONTINUED OPERATIONS (Predecessor)

We distributed our non-STACK assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination.  The distribution of our non-STACK assets and related liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 were part of our overall strategic shift to operate only in the eastern Anadarko Basin.  As a result, the Predecessor’s non-STACK assets and liabilities have been presented as discontinued operations in the consolidated balance sheets.  The operating results directly related to non-STACK assets and liabilities have been segregated and presented as discontinued operations within the condensed consolidated financial statements in the 2018 Predecessor Period and the 2017 Predecessor Periods. 

Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bear simple interest at 10%.  In connection with the Transactions described in Note 1 – Description of Business, the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset distribution.  The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest.  Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million and $0.6 million for the three months ended June 30, 2017 (Predecessor) and 2017 Predecessor Period, respectively.


18


The assets and liabilities directly related to the non-STACK assets presented as discontinued operations in the consolidated balance sheets were as follows (in thousands):
໿
 
Predecessor
 
December 31, 2017
Assets associated with discontinued operations:
 
Current assets
 
Cash
$
61

Accounts receivable
4,980

Other receivables
154

Total current assets
5,195

Noncurrent assets
 
Investments in LLC - Cost
9,000

Proved oil and natural gas properties, net
15,408

Unproved properties, net
15,504

Land
2,706

Other long-term assets
1,167

Total noncurrent assets
43,785

Total assets associated with discontinued operations
$
48,980


 
Liabilities associated with discontinued operations:
 
Current liabilities
 
Accounts payable and accrued liabilities
$
7,882

Asset retirement obligations 
7,537

Total current liabilities
15,419

Noncurrent liabilities
 
Asset retirement obligations, net of current
37,049

Founder's note
28,166

Other long-term liabilities
1,647

Total noncurrent liabilities
66,862

Total liabilities associated with discontinued operations
$
82,281



19


The operating results directly related to the non-STACK assets and liabilities presented as discontinued operations within the consolidated financial statements were as follows (in thousands):
໿

Predecessor

Three Months Ended
June 30, 2017
 
January 1, 2018
Through
February 8, 2018
 
Six Months Ended
June 30, 2017
Operating revenues and other:
 
 
 
 
 
Oil
$
12,723

 
$
1,617

 
$
25,128

Natural gas
2,494

 
1,023

 
5,588

Natural gas liquids
495

 
236

 
1,042

Other revenues
86

 
16

 
202

Total operating revenues
15,798

 
2,892


31,960

Loss on sale of assets

 
(1,923
)
 

Gain on acquisition of oil and gas properties
1,626

 

 
1,626

Total operating revenues and other
17,424

 
969


33,586

Operating expenses:
 
 
 
 
 
Lease operating expense
7,096

 
1,770

 
15,056

Marketing and transportation expense
347

 
83

 
728

Production taxes
1,855

 
167

 
3,657

Workover expense
913

 
127

 
1,708

Exploration expense
3,073

 

 
6,168

Depreciation, depletion and amortization
6,384

 
630

 
12,210

Impairment expense
27,904

 
5,560

 
27,936

Accretion expense
450

 
101

 
926

General and administrative expense
35

 
21

 
47

Total operating expenses
48,057

 
8,459


68,436

Interest expense
(301
)
 
(103
)
 
(599
)
Loss from discontinued operations, net of state income taxes
$
(30,934
)
 
$
(7,593
)
 
$
(35,449
)

The total operating and investing cash flows of the non-STACK assets were as follows (in thousands):
໿

Predecessor

 
January 1, 2018
Through
February 8, 2018
 
Six Months Ended
June 30, 2017
Total operating cash flows of discontinued operations
 
$
(6,838
)
 
$
8,761

Total investing cash flows of discontinued operations
 
(570
)
 
(10,512
)


NOTE 8 FAIR VALUE MEASUREMENTS

We follow ASC 820, which provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

In connection with our acquisition, we recorded the fair value of our $500 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $530.1 million at June 30, 2018 (Successor).  This estimation is based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 11— Long-Term Debt, Net for information on long-term debt.

20



We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the inputs used to determine fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. During the six months ended June 30, 2017, certain of our oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $2.1 million, resulting in an impairment charge of $1.2 million.  Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

New additions to asset retirement obligations result from estimations for new or acquired properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $0.9 million, zero and $0.6 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:


Level 1
 
Level 2
 
Level 3
 
Total

(in thousands)
At June 30, 2018: (Successor)
 
 
 
 
 
 
 
Financial Assets:
 
 
 
 
 
 
 
Derivative contracts for oil and natural gas
 
$
4,692

 
 
$
4,692

Financial Liabilities:
 
 
 
 
 
 
 
Derivative contracts for oil and natural gas
 
$
48,820

 
 
$
48,820

At December 31, 2017: (Predecessor)
 
 
 
 
 
 
 
Financial Assets:
 
 
 
 
 
 
 
Derivative contracts for oil and natural gas
 
$
4,416

 
 
$
4,416

Financial Liabilities:
 
 
 
 
 
 
 
Derivative contracts for oil and natural gas
 
$
24,609

 
 
$
24,609


The amounts above are presented on a gross basis.  We will net the value of assets and liabilities with the same counterparty where master netting agreements are in place for purposes of presentation in our consolidated balance sheets. For additional information on derivative contracts, see Note 9 – Derivative Financial Instruments.


NOTE 9 DERIVATIVE FINANCIAL INSTRUMENTS

We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our derivative contracts are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 11— Long Term Debt, Net, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The derivative contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production equivalent to volumes in gallons (gal) per month. The derivative contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a

21


designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes. 

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.  As of June 30, 2018, we are not a party to any interest rate swap agreements.

We have not designated any of our derivative contracts as fair value or cash flow hedges.  Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the condensed consolidated statements of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed consolidated balance sheets. Likewise, derivative liabilities could be presented in a derivative asset account. 

The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

Fair Values of Derivative Contracts:
໿

 
June 30, 2018 (Successor)
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)
Derivative financial instruments, current assets
 
$
1,934

 
$
(1,934
)
 
$

Derivative financial instruments, long-term assets
 
2,758

 
(2,758
)
 

Total
 
$
4,692


$
(4,692
)

$


໿
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)
Derivative financial instruments, current liabilities
 
$
39,677

 
$
(1,934
)
 
$
37,743

Derivative financial instruments, long-term liabilities
 
9,143

 
(2,758
)
 
6,385

Total
 
$
48,820


$
(4,692
)

$
44,128


໿

 
December 31, 2017 (Predecessor)
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)
Derivative financial instruments, current assets
 
$
1,406

 
$
(1,190
)
 
$
216

Derivative financial instruments, long-term assets
 
3,010

 
(3,002
)
 
8

Total
 
$
4,416


$
(4,192
)

$
224


໿
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)
Derivative financial instruments, current liabilities
 
$
20,493

 
$
(1,190
)
 
$
19,303

Derivative financial instruments, long-term liabilities
 
4,116

 
(3,002
)
 
1,114

Total
 
$
24,609


$
(4,192
)

$
20,417


22



The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations (in thousands):

໿

Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
Derivatives not
Three
 
 
Three
 
February 9, 2018
 
 
January 1, 2018
 
Six
designated as hedging
Months Ended
 
 
Months Ended
 
Through
 
 
Through
 
Months Ended
instruments under ASC 815
June 30, 2018
 
 
June 30, 2017
 
June 30, 2018
 
 
February 8, 2018
 
June 30, 2017
Gain (loss) on derivative contracts
 
 
 
 
 
 
 
 
 
 
 
Oil commodity contracts
$
(28,712
)
 
 
$
16,451

 
$
(51,291
)
 
 
$
5,431

 
$
42,537

Natural gas commodity contracts
(507
)
 
 
1,830

 
(574
)
 
 
1,867

 
5,728

Natural gas liquids commodity contracts

 
 
(31
)
 

 
 

 
227

Total gain (loss) on derivative contracts
$
(29,219
)
 
 
$
18,250

 
$
(51,865
)

 
$
7,298


$
48,492


Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, under certain circumstances, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility described in Note 11 — Long Term Debt, Net.

If a counterparty were to default on payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the derivative could be lost. The value of our derivative financial instruments would be impacted.

We had the following open derivative contracts for crude oil at June 30, 2018:

OIL DERIVATIVE CONTRACTS
໿
໿

 
Volume
in bbls
 
Weighted
Average
 
Range
Settlement Period and Type of Contract
 
 
 
High
 
Low
2018
 
 

 
 

 
 

 
 

Price Swap Contracts 
 
1,104,000

 
$
53.55

 
$
61.26

 
$
50.27

Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
1,104,000

 
61.28

 
64.60

 
60.50

Long Put Options
 
1,104,000

 
51.67

 
60.00

 
50.00

Short Put Options
 
1,104,000

 
42.08

 
52.50

 
40.00

2019
 
 
 
 
 
 
 
 
Price Swap Contracts 
 
182,500

 
63.03

 
63.03

 
63.03

Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
2,701,000

 
66.31

 
75.20

 
56.50

Long Put Options
 
2,883,500

 
53.80

 
62.00

 
50.00

Short Put Options
 
2,883,500

 
42.72

 
52.00

 
37.50

2020
 
 
 
 
 
 
 
 
Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
183,000

 
60.20

 
60.20

 
60.20

Long Put Options
 
549,000

 
50.67

 
51.00

 
50.00

Short Put Options
 
549,000

 
40.00

 
40.00

 
40.00



23


We had the following open derivative contracts for natural gas at June 30, 2018:

NATURAL GAS DERIVATIVE CONTRACTS

໿

 
Volume in
MMBtu
 
Weighted
Average
 
Range
Settlement Period and Type of Contract
 
 
 
High
 
Low
2018
 
 

 
 

 
 

 
 

Price Swap Contracts 
 
4,142,500

 
$
2.89

 
$
3.09

 
$
2.75

Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
2,292,500

 
3.32

 
3.75

 
3.14

Long Put Options
 
1,987,500

 
2.86

 
2.90

 
2.75

Short Put Options
 
610,000

 
2.40

 
2.40

 
2.40

2019
 
 
 
 
 
 
 
 
Price Swap Contracts 
 
5,405,000

 
2.72

 
3.09

 
2.64

Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
2,475,000

 
3.38

 
3.75

 
3.25

Long Put Options
 
2,025,000

 
2.90

 
2.90

 
2.90

Short Put Options
 
900,000

 
2.40

 
2.40

 
2.40


In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above.  Prices stated in the table above for oil may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of these benchmarks.

We had the following open financial basis swaps at June 30, 2018:

NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS
Volume in MMBtu (1)
 
Reference Price 1 (1)
 
Reference Price 2 (1)
 
Period
 
Weighted
Average Spread
($ per MMBtu)
152,500
 
WAHA
 
NYMEX Henry Hub
 
Nov '18
 
 
Dec '18
 
$
(1.05
)
225,000
 
WAHA
 
NYMEX Henry Hub
 
Jan '19
 
 
Mar '19
 
(1.05
)
4,600,000
 
Tex/OKL Panhandle Eastern Pipeline
 
NYMEX Henry Hub
 
Jul '18
 
 
Dec '18
 
(0.66
)
6,530,000
 
Tex/OKL Panhandle Eastern Pipeline
 
NYMEX Henry Hub
 
Jan '19
 
 
Oct '19
 
(0.74
)
_________________
(1)
Represents short swaps that fix the basis differentials between WAHA, Tex/OKL Panhandle Eastern Pipeline (“PEPL”) and NYMEX Henry Hub.

OIL BASIS SWAP DERIVATIVE CONTRACTS
໿
Volume in bbl (1)
 
Reference Price 1 (1)
 
Reference Price 2  (1)
 
Period
 
Weighted
Average Spread
($ per bbl)
1,104,000
 
CMA Oil
 
WTI
 
Jul '18
 
 
Dec '18
 
$
(0.54
)
_________________
(1)
Represents basis swaps for the basis differentials between NYMEX CMA (Calendar Monthly Average) Roll that reconcile the trade month versus the delivery month for physical contract pricing and WTI.


24


NOTE 10 ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below (in thousands):

໿

2018
Balance, as of January 1 (Predecessor)
$
10,469

Liabilities settled
(63
)
Revisions to estimates
63

Accretion expense
39

Balance, as of February 8 (Predecessor)
$
10,508


 
Balance, as of February 9 (Successor)
$

Liabilities assumed from Business Combination
5,998

Liabilities incurred
877

Liabilities settled
(806
)
Liabilities transferred in sale of properties
(20
)
Revisions to estimates
665

Accretion expense
263

Balance, as of June 30 (Successor)
6,977

Less: Current portion
538

Long-term portion
$
6,439



NOTE 11 LONG-TERM DEBT, NET

Long-term debt, net consisted of the following (in thousands):

໿

Successor
 
 
Predecessor

June 30,
2018
 
 
December 31, 2017

 
 
 
 
Senior secured revolving credit facility
$

 
 
$
117,065

7.875% senior unsecured notes due 2024
500,000

 
 
500,000

Unamortized premium on senior unsecured notes
31,584

 
 

Unamortized deferred financing costs

 
 
(9,625
)
Total long-term debt, net
$
531,584


 
$
607,440


Senior Secured Revolving Credit Facility (Successor). In connection with the consummation of the Business Combination, all indebtedness under the senior secured revolving credit facility was repaid in full. On February 9, 2018, and in connection with the closing of the AM Contribution Agreement (as described in Note 1), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, our borrowing base was increased to $400.0 million until the next scheduled redetermination in October 2018. The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing if we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of June 30, 2018, we have no borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit.

The principal amounts borrowed are payable on the maturity date of February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% and 3.00%.  Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-

25


month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%.  The next scheduled redetermination of our borrowing base is in October 2018. The borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under the Eighth A&R credit facility are secured by the first priority liens on substantially all of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged collateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.

The Eighth A&R credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and general and administrative expenses ("G&A") incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the tax receivable agreement.

The Eighth A&R credit facility also requires us to maintain the following two financial ratios:
a current ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and
a leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) annualized by multiplying EBITDAX for the period of (a) the fiscal quarter ending June 30, 2018 times 4, (b) the two fiscal quarter periods ending September 30, 2018 times 2 (c) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (d) for each fiscal quarter on or after March 31, 2019, EBITDAX for the four-fiscal quarter period then ended, of not greater than 4.0 to 1.0.

As of June 30, 2018, we were in compliance with the financial ratios described above.

Senior Secured Revolving Credit Facility (Predecessor).  As of December 31, 2017, the Company had $117.1 million outstanding.  At the date of the Business Combination, the outstanding balance under our credit facility was paid off.

Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) which were issued at par by us and our wholly-owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016.  The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017

The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes for an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our

26


credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.

The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. 

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of the purchase.  The closing of the Business Combination with AMR did not constitute as a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in AMH GP.  See Note 5 — Business Combination (Successor) to the consolidated financial statements for further detail.

The indenture contains customary events of default, including: 
default in any payment of interest on the senior notes when due, continued for 30 days;
default in the payment of principal or premium, if any, on the senior notes when due;
failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;
default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;
certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and
failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20 million.

If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.

As of June 30, 2018, we were in compliance with the indentures governing the senior notes.

Bond Premium (Successor). As discussed in Note 5, the fair value of our senior notes as of the acquisition date was $533.6 million.  The bond premium of $33.6 million is being amortized over the respective term of the senior notes.  The bond premium amortization recognized in interest expense was $1.2 million and $2.1 million for the three months ended June 30, 2018 (Successor) and the Successor Period, respectively. The unamortized bond premium related to the senior notes is included as a component of long-term debt in the consolidated balance sheet as of June 30, 2018

Deferred financing costs. As of December 31, 2017 (Predecessor), we had $11.4 million of unamortized deferred financing costs related to both our senior notes and the Eight A&R credit facility. As a result of the Business Combination, our unamortized deferred financing costs have been adjusted to a fair value of zero at February 9, 2018.  During the Successor Period, we incurred additional deferred financing costs related to the Eighth A&R credit facility of $1.4 million. These costs are reflected as deferred financing costs, net in other noncurrent assets in the consolidated balance sheets as of June 30, 2018. The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations. For the three months ended June 30, 2018 (Successor) and 2017 (Predecessor), the amortization of deferred financing costs was $0.1 million and $0.5 million, respectively. For the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0.1 million, $0.2 million and $1.5 million, respectively.   


NOTE 12 ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the details of accounts payable and accrued liabilities (in thousands):

໿

27



Successor
 
 
Predecessor

June 30,
2018
 
 
December 31, 2017
Accruals for capital expenditures
$
61,982

 
 
$
48,771

Revenues and royalties payable
36,451

 
 
29,514

Accruals for operating expenses/taxes
8,880

 
 
14,632

Accrued interest
1,760

 
 
2,587

Derivative settlement payable
4,510

 
 
2,106

Other
4,524

 
 
4,301

Total accrued liabilities
118,107


 
101,911

Accounts payable
25,000

 
 
68,578

Accounts payable and accrued liabilities
$
143,107


 
$
170,489



NOTE 13 COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims. Various landowners have sued us in lawsuits concerning several fields in which we have, or historically had, operations.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at June 30, 2018.

Title/lease disputes. Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.

Litigation (Predecessor)On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our former subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish.  Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located.  Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon.  The property was originally owned by Exxon and was sold to TMRC.  TMRC subsequently sold the property to Extex.  On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter.  On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon.  On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement.  In connection with the Business Combination, the liability was included in the distribution of our non-STACK assets to the AM Contributor.

On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty.  The suit alleges that the AMH Parties made improper post production deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells.  The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case.  In June 2017, the court administratively closed the case following mediation.  As of December 31, 2017, we accrued approximately $4.7 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets and in general and administrative expense (“G&A”) in our condensed consolidated statements of operations in connection with this litigation.  During January 2018, approximately $4.7 million was paid to fund the settlement. On March 12, 2018, the class settlement was approved by the Court.  

Litigation (Successor)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 us. 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 us in contravention of these agreements. Mustang asserts claims for declaratory judgment,

28


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, including us. While we may incur costs or losses in connection with this litigation, we have not accrued a loss contingency because we are currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves

Other contingencies. We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business.  The outcomes cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Performance appreciation rights.  In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014.  The Plan was intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Business Combination with AMR as described in Note 5 resulted in the accelerated vesting and payment of all outstanding PARs.  The value of the PARs that vested upon closing of the Business Combination was approximately $10.6 million and such amount was recorded in G&A in the Successor Period.  Following the closing of the Business Combination, the Plan was terminated.

Nonqualified Deferred CompensationIn 2013, we established a nonqualified deferred compensation plan, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”).  The Retirement Plan was intended to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. In connection with the Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in G&A in the Successor Period. 

Commitments

We lease office space and certain field equipment such as compressors, under long-term operating lease agreements.  On April 1, 2018, we amended the lease agreement for our corporate headquarters located in Houston, Texas.  The amended lease agreement provides for additional office space and extends the original lease term through April 2028.  Due to the amendment, we have additional lease commitment obligations of approximately $17.6 million through April 2028. Any initial rent-free months are amortized over the life of the lease.

The Company has entered into certain firm transportation contracts that extend through 2028.  At June 30, 2018, the future minimum commitments related to these contracts were approximately $1.7 million a year.


NOTE 14 SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Declines in oil and/or natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas, and natural gas liquids price derivative contracts. See Note 9 – Derivative Financial Instruments for further details on derivatives.


NOTE 15 PARTNERS’ CAPITAL

Management and Control:   Our Seventh Amended and Restated Agreement of Limited Partnership (the “Seventh Amended Partnership Agreement”) currently provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by AMH GP referred to as “GP Units”.  AMH GP owns all the GP Units and in connection with the Business Combination, SRII Opco owns all the LP Units. 


29


As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP.  The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP.

SRII Opco is the sole owner of Class A Units and owns 90% of the Class B Units.  Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company, and HPS Investment Partners, LLC, a Delaware limited liability company, own an aggregate 10% of the Class B Units.  AMH GP’s Board of Directors are selected by the Class B members.  Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement.

The Seventh Amended Partnership Agreement specifies the manner in which we will make cash distribution to our partners.  When AMH GP so directs, we shall make distributions of Net Cash Flow (as defined in the Seventh Amended Partnership Agreement) to the limited partner.


NOTE 16 EQUITY-BASED COMPENSATION

Equity-based compensation (Successor)

Following the closing of the Business Combination, AMR adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”).  A total of 50,000,000 shares of AMR’s Class A Common Stock is reserved for issuance under the LTIP.  The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”) and nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in AMR’s Class A Common Stock.  Prior to the Business Combination, we did not have any equity-based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards were made on February 9, 2018.  During the Successor Period, AMR recognized non-cash stock-based compensation expense of $6.4 million resulting from stock options, restricted stock, and RSUs awards which is included in general and administrative expense in the accompanying consolidated statements of operations.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.

We recognize compensation expense on a straight-line basis for service-based grants over the vesting period.  The fair value of restricted stock awards is determined based on the estimated fair market value of our Class A Common Stock on the date of grant.

Stock options.  Options that have been granted under the LTIP expire seven years from the grant date and generally vest in one-third increments each year on the anniversary date following the date of grant, based on continued employment. The exercise price for an option granted under the LTIP may not be below the fair value of AMR’s Class A Common Stock on the grant date.  

Information about outstanding stock options is summarized in the table below:
໿

Successor

Stock Options
 
Weighted Average Grant - Date Fair Value
 
Weighted Average Remaining Term (in years)
 
Aggregate Intrinsic Value (in thousands)
Outstanding as of February 9, 2018

 
$