Company Quick10K Filing
Quick10K
Alta Mesa Holdings
10-Q 2019-06-30 Quarter: 2019-06-30
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-09-07 Bankruptcy, Off-BS Arrangement, Officers, Regulation FD, Exhibits
8-K 2019-08-13 Off-BS Arrangement
8-K 2019-07-02 Enter Agreement, Officers, Exhibits
8-K 2019-05-17 Earnings, Exhibits
8-K 2019-04-30 Other Events
8-K 2019-02-25 Earnings, Regulation FD, Exhibits
8-K 2019-01-07 Officers, Regulation FD, Exhibits
8-K 2018-12-20 Enter Agreement, Officers, Regulation FD, Exhibits
8-K 2018-11-13 Earnings, Regulation FD, Exhibits
8-K 2018-10-29 Earnings, Regulation FD, Exhibits
8-K 2018-07-02 Accountant, Officers, Exhibits
8-K 2018-02-27 Earnings, Regulation FD, Exhibits
8-K 2018-02-08 Enter Agreement, M&A, Off-BS Arrangement, Shareholder Rights, Control, Officers, Regulation FD, Exhibits
8-K 2018-01-09 Regulation FD, Exhibits
PRTX Protalex 26
PVCT Provectus Biopharmaceuticals 23
MEEC Midwest Energy Emissions 15
VRME Verifyme 10
LEAI Legacy Education Alliance 9
VISM Visium Technologies 0
RAS RAIT Financial Trust 0
SVR Syniverse 0
TALIC Transamerica Advisors Life Insurance 0
NHEL Natural Health Farm Holdings 0
ALTMS 2019-06-30
Part I - Financial Information
Item 1. Financial Statements
Note 1 - Description of Business and Basis of Presentation
Note 2 - Summary of Significant Accounting Policies
Note 3 - Adoption of Asu No. 2016-02, Leases
Note 4 - Supplemental Cash Flow Information
Note 5 - Receivables
Note 6 - Property and Equipment
Note 8 - Derivatives
Note 9 - Accounts Payable and Accrued Liabilities
Note 10 - Asset Retirement Obligations
Note 11 - Debt
Note 12 - Commitments and Contingencies
Note 13 - Significant Concentrations
Note 14 - Equity-Based Compensation (Successor)
Note 15 - Related Party Transactions
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II - Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-31.1 amh_exhibit311-06302019.htm
EX-31.2 amh_exhibit312-06302019.htm
EX-32.1 amh_exhibit321-06302019.htm
EX-32.2 amh_exhibit322-06302019.htm

Alta Mesa Holdings Earnings 2019-06-30

ALTMS 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 altms-063019x10q.htm 10-Q Document

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

x    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2019
OR
¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___ to___             
Commission file number: 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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
None
None
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    No  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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)    Yes  x    No   ¨ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨

Accelerated filer
¨
Non-accelerated filer
¨
Smaller reporting company
¨
Emerging growth company
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
 
 
 
 
Page Number
PART I - FINANCIAL INFORMATION
 
                   Condensed Consolidated Statements of Operations
                   Condensed Consolidated Balance Sheets
                   Condensed Consolidated Statements of Cash Flows
                   Notes to Condensed Consolidated Financial Statements
PART II - OTHER INFORMATION
 



Glossary of Terms

The definitions and abbreviations set forth below apply to the indicated terms throughout this filing.
Company Specific Terms -
 
2018 10-K -
Alta Mesa Holdings, LP Annual Report on Form 10-K for the year ended December 31, 2018.
2024 Notes -
$500 million aggregate principal amount of 7.875% senior unsecured notes due December 2024.
Alta Mesa RBL -
Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent.
AMR -
Alta Mesa Resources, Inc., our parent company.
ARM -
ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives.
BCE -
BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -
The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
High Mesa -
High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -
High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
Predecessor Period -
The period from January 1, 2018 through February 8, 2018.
SRII Opco -
SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Successor Period -
The period from February 9, 2018 through December 31, 2018, and all periods thereafter.
Oil, Gas and Other Terms -
 
Basin -
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -
Barrels per day.
Boe -
One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio at energy content, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -
One Boe per day.
Btu or
British Thermal Unit -
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -
The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
DD&A -
Depreciation, depletion and amortization.
Development costs -
Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Development project -
A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Differential -
An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -
A well found to be incapable of producing hydrocarbons in commercial quantities.
EBITDAX -
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.

i


Enhanced recovery -
The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -
A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Formation -
A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -
A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Held by production -
Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum paying quantity of production.
Horizontal drilling -
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -
The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -
One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbblsd -
One thousand barrels per day.
MBoe -
One thousand boe.
MBoed -
One thousand boe per day.
Mcf -
One thousand cubic feet of natural gas.
Mcfd -
One thousand cubic feet per day.
MMBtu -
One million British thermal units.
MMBtud -
One million British thermal units per day.
MMcf -
One million cubic feet of natural gas.
MMcfd -
One million cubic feet per day.
Net acres -
The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -
Production that is owned by us after royalties and production attributable to other owners.
NGLs or natural gas liquids -
Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -
The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -
The New York Mercantile Exchange.
Prospect -
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved properties -
Properties with proved reserves.
Proved reserves -
Quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.
Realized price -
The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -
The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

ii


Resources -
Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
Spacing -
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
STACK -
An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.
Unproved properties -
Properties with no proved reserves.
Wellbore -
The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
Working interest -
The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -
Operations on a producing well to restore or increase production.


iii


Cautionary Statement Regarding Forward-Looking Statements
The information in this Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our ability to continue as a going concern, strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could”, “should”, “will”, “plan”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project,” the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 10-K”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about:
our and our parent’s ability to continue as going concerns;
the sufficiency of liquidity to fund our operations and capital expenditures;
our access to capital, including constraints from the cost and availability of debt and equity financing;
our ability to comply with, or amend the terms of, the covenants and restrictions imposed by our debt agreements, including our ability to repay amounts borrowed under the Alta Mesa RBL that exceed the current borrowing base;
our ability to execute our stated business strategy;
our reserve quantities and the present value of our reserves;
our ability to replace the reserves we produce through drilling and through acquisitions;
our exploration and drilling prospects, inventories, projects and programs;
our drilling, completion and production technology;
future oil and gas prices;
the supply and demand for our production;
the timing and amount of our future production;
our hedging strategy and expected results;
competition and government regulation;
our ability to obtain permits and governmental approvals;
expected or anticipated regulatory changes, including to the Oklahoma forced pooling system;
pending legal and environmental matters;
our future drilling plans, spacing plans and development pace;
our marketing of our production;
our leasehold or business acquisitions;
our costs of developing our properties;
our ability to hire, train or retain qualified personnel;
general economic conditions;
operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids and crude oil;
our future operating results, including production levels, initial production rates and yields in our type curve areas;
the costs, terms and availability of midstream services;
our ability to collect receivables from High Mesa, Inc. and its subsidiaries; and
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that any forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation or the SEC investigation, difficulties in obtaining necessary approvals and permits, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt

1


agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described in Risk Factors of our 2018 10-K.

Estimating reserve quantities of oil, natural gas and NGLs is complex, inexact and relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires making a number of economic assumptions, such as sales prices, the relative mix of oil, natural gas and NGLs that will be ultimately produced, drilling and operating costs, capital expenditures, the effect of government regulation, taxes and availability of funds.  Future prices received for production and costs may vary, perhaps significantly, from the assumptions used in our estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of development and related production. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report or in the 2018 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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


2


PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

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

Successor
 
 
Predecessor

Three Months Ended
June 30, 2019
 
Three Months Ended
June 30, 2018
 
 
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Revenue
 
 
 
 
 
 
 
 
 
 
 
Oil
$
90,668

 
$
75,291

 
 
$
177,031

 
$
115,569

 
 
$
30,972

Natural gas
12,384

 
7,980

 
 
30,834

 
13,190

 
 
4,276

Natural gas liquids
10,251

 
10,241

 
 
21,467

 
14,955

 
 
4,000

Other
330

 
2,229

 
 
898

 
2,784

 
 
888

Operating revenue
113,633

 
95,741

 
 
230,230

 
146,498

 
 
40,136

Gain (loss) on sale of assets

 
(63
)
 
 
1,483

 
5,076

 
 
840

Gain (loss) on derivatives
12,412

 
(29,219
)
 
 
(11,365
)
 
(51,230
)
 
 
6,663

Total revenue
126,045

 
66,459

 
 
220,348

 
100,344

 
 
47,639

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
Lease operating
19,123

 
12,679

 
 
44,231

 
20,996

 
 
4,408

Transportation and marketing
19,614

 
11,206

 
 
37,375

 
16,788

 
 
3,725

Production taxes
5,117

 
2,606

 
 
10,600

 
4,021

 
 
953

Workovers
412

 
333

 
 
609

 
1,578

 
 
423

Exploration
3,289

 
8,083

 
 
5,343

 
9,668

 
 
7,003

Depreciation, depletion and amortization
34,504

 
26,670

 
 
69,179

 
37,708

 
 
11,670

Impairment of assets
6,500

 

 
 
6,500

 

 
 

General and administrative
15,723

 
17,811

 
 
36,670

 
52,465

 
 
21,234

Total operating expenses
104,282

 
79,388

 
 
210,507

 
143,224

 
 
49,416

Operating income
21,763

 
(12,929
)
 
 
9,841

 
(42,880
)
 
 
(1,777
)
Other income (expense)
 
 
 
 
 
 
 
 
 
 
 
Interest expense
(14,071
)
 
(10,361
)
 
 
(26,901
)
 
(15,557
)
 
 
(5,511
)
Interest income and other
54

 
820

 
 
81

 
1,366

 
 
172

Total other expense, net
(14,017
)
 
(9,541
)
 
 
(26,820
)
 
(14,191
)
 
 
(5,339
)
Income (loss) from continuing operations before income taxes
7,746

 
(22,470
)
 
 
(16,979
)
 
(57,071
)
 
 
(7,116
)
Income tax provision (benefit)

 
7

 
 

 
7

 
 

Income (loss) from continuing operations
7,746

 
(22,477
)
 
 
(16,979
)
 
(57,078
)
 
 
(7,116
)
Loss from discontinued operations, net of tax

 

 
 

 

 
 
(7,746
)
Net income (loss)
$
7,746

 
$
(22,477
)
 
 
$
(16,979
)
 
$
(57,078
)
 
 
$
(14,862
)
The accompanying notes are an integral part of these financial statements.

3


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

June 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
78,275

 
$
12,984

Restricted cash
890

 
1,001

Accounts receivable, net
61,662

 
68,370

Other receivables
3,530

 
6,267

Related party receivables, net
13,149

 
24,282

Notes receivable from related parties, net

 

Prepaid expenses and other current assets
4,623

 
747

Derivatives
4,727

 
16,423

Total current assets
166,856

 
130,074

Property and equipment, net
 
 
 
Oil and gas properties, successful efforts method
784,079

 
763,337

Other property and equipment
37,371

 
38,147

Total property and equipment
821,450

 
801,484

Other assets
 
 
 
Operating lease right-of-use assets, net
7,871

 

Deferred financing costs, net
1,021

 
1,151

Deposits and other long-term assets
38

 
63

Derivatives
2,508

 
2,947

Total other assets
11,438

 
4,161

Total assets
$
999,744

 
$
935,719


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


June 30, 2019
 
December 31, 2018
LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities
 
 
 
Current portion of debt
$
871,162

 
$

Accounts payable and accrued liabilities
91,694

 
197,064

Accounts payable - related party
222

 
3,425

Advances from non-operators
1,755

 
5,193

Advances from related party
4,003

 
9,822

Asset retirement obligations
44

 
2,079

Current operating lease liability
938

 

Derivatives
840

 
1,710

Total current liabilities
970,658

 
219,293

Long-term liabilities
 
 
 
Asset retirement obligations, net of current portion
12,293

 
9,330

Long-term debt, net

 
690,123

Operating lease liabilities, net of current portion
13,733

 

Derivatives
189

 
180

Total long-term liabilities
26,215

 
699,633

Total liabilities 
996,873

 
918,926

Commitments and contingencies


 


Partners’ capital
2,871

 
16,793

Total liabilities and partners’ capital
$
999,744

 
$
935,719

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


4


ALTA MESA HOLDINGS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)
(in thousands)
 
໿
 
Predecessor
Balance, December 31, 2017
$
154,445

Distribution of non-STACK oil and gas assets, net of associated liabilities
43,482

Net loss
(14,862
)
Balance, February 8, 2018
$
183,065

 
 
 
Successor
Balance, February 9, 2018
$
1,535,891

Contributions
560,344

Equity-based compensation expense
2,768

Net loss
(34,601
)
Balance, March 31, 2018
2,064,402

Issuance of additional purchase consideration
9,467

Equity-based compensation expense
3,621

Distributions
(7,000
)
Net loss
(22,477
)
Balance, June 30, 2018
$
2,048,013

 
 
Balance, December 31, 2018
$
16,793

Equity-based compensation expense
1,661

Net loss
(24,725
)
Balance, March 31, 2019
(6,271
)
Equity-based compensation expense
1,396

Net income
7,746

Balance, June 30, 2019
$
2,871

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

5


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

Successor
 
 
Predecessor

Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Cash flows from operating activities:
 
 
 
 
 
 
Net loss
$
(16,979
)
 
$
(57,078
)
 
 
$
(14,862
)
Adjustments to reconcile net loss to cash from operating activities:
 
 
 
 
 
 
Depreciation, depletion, amortization and accretion
69,179

 
37,708

 
 
12,554

Non-cash lease expense
1,587

 

 
 

Provision for uncollectible receivables
1,177

 

 
 

Impairment of assets
6,500

 

 
 
5,560

Amortization of deferred financing costs
139

 
80

 
 
171

Amortization of debt (premium) discount
(2,462
)
 
(2,051
)
 
 

Equity-based compensation expense
3,057

 
6,389

 
 

Non-cash exploration expense
388

 
10,658

 
 
4,575

(Gain) loss on derivatives
11,365

 
51,230

 
 
(6,663
)
Cash settlements of derivatives
909

 
(18,334
)
 
 
(2,296
)
Premium paid on derivatives
(1,000
)
 

 
 

Interest converted into debt

 

 
 
103

Interest added to notes receivable from affiliate

 
(417
)
 
 
(85
)
Loss on sale of fixed assets

 
63

 
 
1,923

Impact on cash from changes in:
 
 
 
 
 
 
Accounts receivable
6,384

 
(2,923
)
 
 
(21,184
)
Other receivables
2,737

 
1,426

 
 
(662
)
Receivables from related parties
10,280

 
(18,494
)
 
 
(117
)
Prepaid expenses and other non-current assets
(3,853
)
 
7,810

 
 
(591
)
Advances from related party
(5,819
)
 
(10,371
)
 
 
24,116

Settlement of asset retirement obligations


 
(806
)
 
 
(63
)
Accounts payable to related party

(3,203
)
 
(4,994
)
 
 

Accounts payable, accrued liabilities and other liabilities
(17,281
)
 
(45,385
)
 
 
23,857

Operating lease obligations
(1,287
)
 

 
 

Cash from operating activities
61,818

 
(45,489
)
 
 
26,336

Cash flows from investing activities:
 
 
 
 
 
 
Capital expenditures
(180,138
)
 
(319,042
)
 
 
(36,695
)
Acquisitions, net of cash acquired

 

 
 
(1,218
)
Proceeds from sale of assets

 
11,299

 
 

Cash from investing activities
(180,138
)
 
(307,743
)
 
 
(37,913
)
Cash flows from financing activities:
 
 
 
 
 
 
Proceeds from long-term debt borrowings
183,500

 

 
 
60,000

Repayments of long-term debt

 
(134,065
)
 
 
(43,000
)
Deferred financing costs paid

 
(1,366
)
 
 

Capital distributions

 
(7,000
)
 
 
(68
)
Capital contributions

 
560,344

 
 

Cash from financing activities
183,500

 
417,913

 
 
16,932

Net increase in cash, cash equivalents and restricted cash
65,180

 
64,681

 
 
5,355

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

 
10,345

 
 
4,990

Cash, cash equivalents and restricted cash, end of period
$
79,165

 
$
75,026

 
 
$
10,345

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


6


ALTA MESA HOLDINGS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an 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 commonly referred to as the STACK. Our operations prior to February 9, 2018, also included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the Business Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK.  Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). The 2018 10-K contains substantially more information about our operations and the Business Combination.

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


NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern
We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors:

Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.
Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.
Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions.
On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is

7


a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities.
We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019.
We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.
The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets.
Our ability to collect receivables due from High Mesa and its affiliates

The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:

retained financial advisors to assist in evaluating financial alternatives;
engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief;
considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and
engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.

Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current.

Recently Issued Accounting Standards Applicable to Us
Adopted
Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes 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.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a

8


hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

NOTE 3 — ADOPTION OF ASU NO. 2016-02, LEASES

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities of $15.0 million. There was no adjustment to beginning of period equity.

We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets, although we aspire to sublease our unused office lease space.
Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.
Upon adoption, we selected the following practical expedients:

9


Practical expedient package
 
We did not reassess whether any expired or existing contracts are, or contain, leases.
 
 
We did not reassess the lease classification of any expired or existing leases.
 
 
We did not reassess initial direct costs of any expired or existing leases.
 
 
 
Hindsight practical expedient
 
We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
 
 
 
Easement expedient
 
We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
 
 
 
Combining lease and non-lease components expedient
 
We elected to account for lease and non-lease components as a single component.
 
 
 
Short-term lease expedient
 
We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and our weighted-average discount rates were 14.1%.

Lease Costs
(in thousands)
 
Three Months Ended
June 30, 2019
 
Six Months Ended June 30, 2019
Operating lease cost
 
$
776

 
$
1,587

Variable lease cost
 
473

 
796

Short-term lease cost
 
1,075

 
3,261

Total lease cost
 
$
2,324

 
$
5,644

 
 
 
 
 
Reported as:
 
 
 
 
Lease operating expense
 
$
1,031

 
$
3,326

General and administrative expense
 
1,293

 
2,318

Total lease cost
 
$
2,324

 
$
5,644


Operating Lease Liability Maturities as of June 30, 2019

10


Fiscal year
 
(in thousands)
Remainder of 2019
 
$
1,470

2020
 
2,965

2021
 
2,942

2022
 
3,010

2023
 
2,718

Thereafter
 
12,647

Total lease payments
 
25,752

Less: imputed interest
 
(11,081
)
Present value of operating lease liabilities
 
$
14,671

 
 
 
Current portion of operating lease liabilities
 
$
938

Operating lease liabilities, net of current portion
 
13,733

Present value of operating lease liabilities
 
$
14,671


Operating Lease Payment Obligations as of December 31, 2018

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

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

NOTE 4 — SUPPLEMENTAL CASH FLOW INFORMATION

Successor
 
 
Predecessor
(in thousands)
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Supplemental cash flow information:
 
 
 
 
 
 
Cash paid for interest
$
25,070

 
$
21,216

 
 
$
1,145

Cash paid for state income taxes, net of refunds

 
6

 
 

Non-cash investing and financing activities:
 
 
 
 
 
 
Increase in asset retirement obligations
634

 
877

 
 

Increase (decrease) in accruals or payables for capital expenditures
(91,639
)
 
(27,646
)
 
 
4,896

Distribution of non-STACK assets, net of liabilities

 

 
 
43,482


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


NOTE 5 — RECEIVABLES

Accounts Receivable
(in thousands)
June 30, 2019
 
December 31, 2018
Production sales
$
29,730

 
$
31,532

Joint interest billings
20,836

 
18,147

Pooling interest (1)
11,506

 
18,786

Allowance for doubtful accounts
(410
)
 
(95
)
Total accounts receivable, net
$
61,662

 
$
68,370

_________________
(1)
Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.


Related Party Receivables
(in thousands)
June 30, 2019
 
December 31, 2018
Related party receivables
$
23,037

 
$
33,316

Allowance for doubtful accounts
(9,888
)
 
(9,034
)
Related party receivables, net
13,149

 
24,282

 
 
 
 
Notes receivable from related parties
13,403

 
13,403

Allowance for doubtful accounts
(13,403
)
 
(13,403
)
Notes receivable from related parties, net

 

Total related party receivables, net
$
13,149

 
$
24,282


KFM Receivables


11


We have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, we incurred $30.8 million, $13.6 million, and $3.1 million, respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the fees from midstream services that KFM provided to us totaling $4.6 million and $11.2 million at June 30, 2019 and December 31, 2018, respectively.

In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of December 31, 2018, related party receivables of $8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019.

AMR Receivables

We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of June 30, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $8.5 million and $3.3 million, respectively.

Management Services Agreement with High Mesa

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

Additions
894

Payments
(1,072
)
High Mesa related party receivable at June 30, 2019
9,888

Allowance for uncollectibility(1)
(9,888
)
Balance at June 30, 2019, net
$

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

Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods, unless terminated by either party upon at least 90-days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation

12


relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI.  The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note when it was not paid at maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.

In addition, we have an $8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the $8.5 million note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

NOTE 6 — PROPERTY AND EQUIPMENT

(in thousands)
June 30, 2019
 
December 31, 2018
Oil and gas properties
 
 
 
Unproved properties
$
76,665

 
$
74,217

Proved oil and gas properties
2,196,605

 
2,110,346

Accumulated depletion and impairment
(1,489,191
)
 
(1,421,226
)
Proved oil and gas properties, net
707,414

 
689,120

Total oil and gas properties, net
784,079

 
763,337

Other property and equipment
 
 
 
Land
5,059

 
5,059

Fresh water wells
27,372

 
27,366

Produced water disposal system
3,590

 
3,608

Office furniture, equipment and vehicles
2,825

 
2,840

Accumulated depreciation
(1,475
)
 
(726
)
Other property and equipment, net
37,371

 
38,147

Total property and equipment, net
$
821,450

 
$
801,484



13


Depletion and Depreciation Expense

 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
June 30, 2019
 
Three Months Ended
June 30, 2018
 
 
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Oil and gas properties depletion
$
33,923

 
$
26,086

 
 
$
67,965

 
$
36,859

 
 
$
11,021

Other property and equipment depreciation
341

 
423

 
 
749

 
586

 
 
609

Total depletion and depreciation
$
34,264

 
$
26,509

 
 
$
68,714

 
$
37,445

 
 
$
11,630


Impairment

During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment. Therefore, we did not conduct further analysis on the recognition of additional impairment.


14


NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period.

Predecessor
(in thousands)
January 1, 2018
Through
February 8, 2018
Revenue
 
Oil
$
1,617

Natural gas
1,023

Natural gas liquids
236

Other
16

Operating revenue
2,892

Loss on sale of assets
(1,923
)
Total revenue
969

Operating expenses
 
Lease operating
1,770

Transportation and marketing
83

Production taxes
167

Workovers
127

Depreciation, depletion and amortization
884

Impairment of assets
5,560

General and administrative
21

Total operating expenses
8,612

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


Predecessor
(in thousands)
January 1, 2018
Through
February 8, 2018
Total operating cash flows of discontinued operations
$
2,974

Total investing cash flows of discontinued operations
(601
)

NOTE 8 — DERIVATIVES  

All of our derivatives have the lenders under the Alta Mesa RBL as counterparty, and are collateralized by the security interests thereunder. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes and none have been designated as hedges under GAAP.

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

 
June 30, 2019
Balance sheet location
 
Gross
fair value
of assets
 
Gross liabilities
offset against assets
in the Balance Sheet
 
Net fair
value of assets
presented in
the Balance Sheet

 
(in thousands)
Derivatives, current assets
 
$
13,855

 
$
(9,128
)
 
$
4,727

Derivatives, long-term assets
 
11,977

 
(9,469
)
 
2,508

Total
 
$
25,832

 
$
(18,597
)
 
$
7,235

Balance sheet location
 
Gross
fair value
of liabilities
 
Gross assets
offset against liabilities
in the Balance Sheet
 
Net fair
value of liabilities
presented in
the Balance Sheet

 
(in thousands)
Derivatives, current liabilities
 
$
9,968

 
$
(9,128
)
 
$
840

Derivatives, long-term liabilities
 
9,658

 
(9,469
)
 
189

Total
 
$
19,626

 
$
(18,597
)
 
$
1,029


 
December 31, 2018
Balance sheet location
 
Gross
fair value
of assets
 
Gross liabilities
offset against assets
in the Balance Sheet
 
Net fair
value of assets
presented in
the Balance Sheet

 
(in thousands)
Derivatives, current assets
 
$
22,512

 
$
(6,089
)
 
$
16,423

Derivatives, long-term assets
 
7,910

 
(4,963
)
 
2,947

Total
 
$
30,422

 
$
(11,052
)
 
$
19,370

Balance sheet location
 
Gross
fair value
of liabilities
 
Gross assets
offset against liabilities
in the Balance Sheet
 
Net fair
value of liabilities
presented in
the Balance Sheet

 
(in thousands)
Derivatives, current liabilities
 
$
7,799

 
$
(6,089
)
 
$
1,710

Derivatives, long-term liabilities
 
5,143

 
(4,963
)
 
180

Total
 
$
12,942

 
$
(11,052
)
 
$
1,890


The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands):
 
Successor
 
 
Predecessor
Derivatives not designated as hedges
Three Months Ended
June 30, 2019
 
Three Months Ended
June 30, 2018
 
 
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Gain (loss) on derivatives -
 
 
 
 
 
 
 
 
 
 
 
Oil
$
5,134

 
$
(28,712
)
 
 
$
(16,535
)
 
$
(50,656
)
 
 
$
4,796

Natural gas
7,278

 
(507
)
 
 
5,170

 
(574
)
 
 
1,867

Total gain (loss) on derivatives
$
12,412

 
$
(29,219
)
 
 
$
(11,365
)
 
$
(51,230
)
 
 
$
6,663


Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the ensuing month.

We had the following call and put derivatives at June 30, 2019:

15


OIL

 
Remaining Volume
 
Weighted
 
Range
Settlement Period and Type of Contract
 
in bbls
 
Average
 
High
 
Low
2019
 
 

 
 

 
 

 
 

Price Swap Contracts 
 
92,000

 
$
63.03

 
$
63.03

 
$
63.03

Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
1,361,600

 
66.31

 
75.20

 
56.50

Long Put Options
 
1,453,600

 
53.80

 
62.00

 
50.00

Short Put Options
 
1,453,600

 
42.72

 
52.00

 
37.50

2020
 
 
 
 
 
 
 
 
Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
1,017,600

 
63.95

 
73.80

 
59.55

Long Put Options
 
1,566,600

 
56.81

 
62.50

 
50.00

Short Put Options
 
1,566,600

 
42.81

 
50.00

 
37.50

2021
 
 
 
 
 
 
 
 
Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
279,750

 
63.51

 
63.75

 
63.35

Long Put Options
 
659,850

 
46.94

 
55.00

 
41.00

Short Put Options
 
279,750

 
43.00

 
43.00

 
43.00


NATURAL GAS

 
Remaining Volume
 
Weighted
 
Range
Settlement Period and Type of Contract
 
in MMBtu
 
Average
 
High
 
Low
2019
 


 


 


 


Price Swap Contracts
 
7,980,000

 
$
2.67

 
$
2.72

 
$
2.64

Basis Swap Contracts
 
9,680,000

 
(0.72
)
 
(0.49
)
 
(0.93
)
Collar Contracts
 


 


 


 


Short Call Options
 
1,525,000

 
3.19

 
3.20

 
3.17

Long Put Options
 
1,525,000

 
2.70

 
2.70

 
2.70

Short Put Options
 
1,525,000

 
2.20

 
2.20

 
2.20

2020
 


 


 


 


Price Swap Contracts
 
1,284,000

 
2.54

 
2.54

 
2.54

Basis Swap Contracts
 
910,000

 
(0.49
)
 
(0.49
)
 
(0.50
)
Collar Contracts
 


 


 


 


Short Call Options
 
3,874,500

 
3.19

 
3.69

 
2.77

Long Put Options
 
10,749,500

 
2.59

 
3.00

 
2.50

Short Put Options
 
9,696,000

 
2.10

 
2.50

 
2.00

2021
 
 
 
 
 
 
 
 
Collar Contracts
 
 
 
 
 
 
 
 
Short Call Options
 
540,000

 
3.25

 
3.25

 
3.25

Long Put Options
 
2,790,000

 
2.62

 
2.65

 
2.50

Short Put Options
 
2,250,000

 
2.15

 
2.15

 
2.15



16


We had the following basis swaps at June 30, 2019:
Total Gas Volumes in MMBtu(1) over
Remaining Term
 
Reference Price 1 (1)
 
Reference Price 2 (1)
 
Period
 
Weighted
Average Spread
($ per MMBtu)
460,000
 
OneOK
 
NYMEX Henry Hub
 
Jul '19
 
 
Dec '19
 
$
(0.93
)
7,990,000
 
Tex/OKL Panhandle Eastern Pipeline
 
NYMEX Henry Hub
 
Jul '19
 
 
Dec '19
 
(0.70
)
910,000
 
Tex/OKL Panhandle Eastern Pipeline
 
NYMEX Henry Hub
 
Jan '20
 
 
Mar '20
 
(0.49
)
1,230,000
 
San Juan
 
NYMEX Henry Hub
 
Jul '19
 
 
Oct '19
 
(0.81
)
________________
(1)
Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

NOTE 9 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 
໿
(in thousands)
June 30, 2019
 
December 31, 2018
Accounts payable
$
8,871

 
$
20,200

Accruals for capital expenditures
18,477

 
101,214

Revenue and royalties payable
39,232

 
46,870

Accruals for operating expenses
10,701

 
16,355

Accrued interest
5,642

 
1,784

Derivative settlements
743

 
109

Other
8,028

 
10,532

Total accrued liabilities
82,823

 
176,864

Accounts payable and accrued liabilities
$
91,694

 
$
197,064


NOTE 10 — ASSET RETIREMENT OBLIGATIONS 

Successor
 
 
Predecessor
(in thousands)
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Balance, beginning of period
$
11,409

 
$

 
 
$
10,469

Liabilities assumed in Business Combination

 
5,998

 
 

Liabilities incurred
634

 
877

 
 

Liabilities settled
(162
)
 
(806
)
 
 
(63
)
Liabilities transferred in sale of properties

 
(20
)
 
 

Revisions to estimates
(9
)
 
665

 
 
63

Accretion expense
465

 
263

 
 
40

Balance, end of period
12,337

 
6,977

 
 
10,509

Less: Current portion
44

 
538

 
 
33

Long-term portion
$
12,293

 
$
6,439

 
 
$
10,476


NOTE 11 — DEBT
໿

17


(in thousands)
June 30, 2019
 
December 31, 2018
Alta Mesa RBL
$
344,500

 
$
161,000

2024 Notes
500,000

 
500,000

Unamortized premium on 2024 Notes
26,662


29,123

Total debt, net
871,162

 
690,123

Less: Current portion
871,162

 

Long-term debt, net
$

 
$
690,123

Alta Mesa RBL

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

a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and
a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX. 
Before July 2020, and possibly as soon as September 30, 2019, we do not expect to satisfy the leverage ratio. We recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.
At June 30, 2019, inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds.
In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination.
2024 Notes
In connection with the Business Combination, we recorded the fair value of our $500.0 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 $193.8 million at June 30, 2019.  This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination.
Scheduled Maturities of Debt
Fiscal year
 
(in thousands)
2019
 
$

2020
 

2021
 

2022
 

2023
 
344,500

Thereafter
 
500,000


 
$
844,500


Based upon the factors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than the scheduled maturities shown above. We have reported all of our debt as current at June 30, 2019.

NOTE 12 — COMMITMENTS AND CONTINGENCIES 
There have been no material changes during the first six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K.

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NOTE 13 — SIGNIFICANT CONCENTRATIONS 

During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.
Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement.
ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.
 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
June 30, 2019
 
Three Months Ended
June 30, 2018
 
 
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Revenue marketed by ARM on our behalf
$
7,703

 
$
70,601

 
 
$
91,534

 
$
107,944

 
 
$
28,757

 
 
 
 
 
 
 
 
 
 
 
 
Marketing and management fees paid to ARM
$
476

 
$

 
 
$
1,137

 
$

 
 
$

Fees paid to ARM for derivative services
218

 
209

 
 
411

 
283

 
 
66

Total fees paid to ARM
$
694

 
$
209

 
 
$
1,548

 
$
283

 
 
$
66


Receivables from ARM for sales on our behalf were $0.2 million and $38.4 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available. 

NOTE 14 EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows:
 
Successor
 
 
Predecessor
(in thousands)
Three Months Ended
June 30, 2019
 
Three Months Ended
June 30, 2018
 
 
Six Months Ended
June 30, 2019
 
February 9, 2018
Through
June 30, 2018
 
 
January 1, 2018
Through
February 8, 2018
Stock options
$
744

 
$
1,606

 
 
$
1,535

 
$
2,628

 
 
$

Restricted stock awards
563

 
871

 
 
1,425

 
1,412

 
 

Performance-based restricted stock units
89

 
1,144

 
 
97

 
2,349

 
 

Total compensation expense
$
1,396

 
$
3,621

 
 
$
3,057

 
$
6,389

 
 
$


Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year are based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.


19


The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.
NOTE 15 — RELATED PARTY TRANSACTIONS 
As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables.
As of December 31, 2018, we had a payable to AMR of $0.5 million which was settled during the second quarter of 2019.
David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates was his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.
David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $929,428 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to AMH. Mr. McClure separated from the Company in February 2019.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE each bear our respective proportionate working interest share of all subsequent costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. Through June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

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

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed

20


in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the sections titled “Risk Factors” in this Quarterly Report and in our 2018 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview

We are an 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 STACK. We generate revenue principally by the production and sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

As a result of the Business Combination, our identifiable assets acquired and liabilities assumed by our parent company were recorded at their estimated fair values at February 9, 2018 and were pushed down to us.  As a result, our financial statements and certain footnote presentations separate our presentations into two distinct periods, the period before the consummation of the Business Combination (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. Accordingly, the period January 1, 2018 to February 8, 2018 is referred to as the Predecessor Period.

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

As of June 30, 2019, we have a highly contiguous position of approximately 130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and south-eastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense.

We have operated 2 rigs since restarting the program, however following the redetermination of the borrowing base of the Alta Mesa RBL in August 2019, we have decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control.  The success of our business is significantly affected by the price of oil due to its weighting in our production profile. 

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, gas and NGLs prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa RBL.


21