NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Alta Mesa Resources, Inc., together with its consolidated subsidiaries (“we” or “the Company”), 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. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through Kingfisher Midstream, LLC (“KFM”). KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.
We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, exchange, acquisition, purchase, reorganization or similar business combination involving it and one or more businesses. On February 9, 2018 we acquired interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination”, and changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” Our Class A Common Stock and public warrants are listed on the NASDAQ Capital Market (“NASDAQ”) under the symbols “AMR” and “AMRWW,” respectively. However, as a result of our failure to comply with the NASDAQ continued listing requirements, trading of our common stock and warrants will be suspended at the opening of business on September 24, 2019 and will be removed from listing and registration on NASDAQ. The Company expects the common stock and warrants to be traded over the counter under the trading symbols “AMRQ” and “AMRWWQ”, respectively.
In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and associated liabilities to its prior owner, High Mesa Holdings, LP (“High Mesa”). The non-STACK assets and liabilities are reflected as discontinued operations in our financial statements.
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”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three months ended March 31, 2019, are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation.
NOTE 2 — SUMMARY OF 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 a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause
utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $62.3 million.
If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Company, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and, together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order.
The Debtors have begun a marketing process to sell their assets, which may also include the midstream assets of certain of their non-Debtor affiliates. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.
Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.
Because of the default under the Alta Mesa RBL and 2024 Notes arising from our bankruptcy filing, we have reported all of our Upstream debt as current. We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the cash collateral agreement approved by the Bankruptcy Court, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.8 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. Accordingly, we have determined that it is appropriate to also report all of our Midstream debt as current at March 31, 2019. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.
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 in January 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 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 in January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.
NOTE 3 — 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 of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.
We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not currently sublease any of our ROU assets, although we may sublease our unused office lease space in the future.
Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.
Upon adoption, we selected the following practical expedients:
|
|
|
|
Practical expedient package
|
|
We did not reassess whether any expired or existing contracts are, or contain, leases.
|
|
|
We did not reassess the lease classification of any expired or existing leases.
|
|
|
We did not reassess initial direct costs of any expired or existing leases.
|
|
|
|
Hindsight practical expedient
|
|
We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
|
|
|
|
Easement expedient
|
|
We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
|
|
|
|
Combining lease and non-lease components expedient
|
|
We elected to account for lease and non-lease components as a single component.
|
|
|
|
Short-term lease expedient
|
|
We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.
|
As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At March 31, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.3 years and the weighted-average discount rate applied was 14.3%.
Lease Costs
|
|
|
|
|
|
(in thousands)
|
|
Three Months Ended
March 31, 2019
|
Operating lease cost
|
|
$
|
847
|
|
Variable lease cost
|
|
371
|
|
Short-term lease cost
|
|
2,584
|
|
Total lease cost
|
|
$
|
3,802
|
|
|
|
|
Reported in:
|
|
|
Lease operating expense
|
|
$
|
2,615
|
|
General and administrative expense
|
|
1,187
|
|
Total lease cost
|
|
$
|
3,802
|
|
Operating Lease Liability Maturities as of March 31, 2019
|
|
|
|
|
|
Fiscal year
|
|
(in thousands)
|
Remainder of 2019
|
|
$
|
2,288
|
|
2020
|
|
3,081
|
|
2021
|
|
3,047
|
|
2022
|
|
3,108
|
|
2023
|
|
2,718
|
|
Thereafter
|
|
12,647
|
|
Total lease payments
|
|
26,889
|
|
Less: imputed interest
|
|
(11,704
|
)
|
Present value of operating lease liabilities
|
|
$
|
15,185
|
|
|
|
|
Current portion of operating lease liabilities
|
|
$
|
976
|
|
Operating lease liabilities, net of current portion
|
|
14,209
|
|
Present value of operating lease liabilities
|
|
$
|
15,185
|
|
As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.
NOTE 4 — SUPPLEMENTAL CASH FLOW INFORMATION
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|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Supplemental cash flow information:
|
|
|
|
|
|
|
Cash paid for interest
|
$
|
3,527
|
|
|
$
|
1,092
|
|
|
|
$
|
1,145
|
|
Cash paid for income taxes, net of refunds
|
706
|
|
|
—
|
|
|
|
—
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
Increase in asset retirement obligations
|
314
|
|
|
421
|
|
|
|
—
|
|
Increase (decrease) in accruals or payables for capital expenditures
|
(96,865
|
)
|
|
(37,152
|
)
|
|
|
4,896
|
|
Increase in withholding tax accruals for share-based compensation
|
142
|
|
|
—
|
|
|
|
—
|
|
Distribution of non-STACK assets, net of liabilities
|
—
|
|
|
—
|
|
|
|
43,482
|
|
The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
March 31, 2019
|
|
March 31, 2018
|
|
|
February 8, 2018
|
Cash and cash equivalents
|
$
|
36,512
|
|
|
$
|
261,063
|
|
|
|
$
|
9,070
|
|
Restricted cash
|
798
|
|
|
1,295
|
|
|
|
1,275
|
|
Total cash, cash equivalents and restricted cash
|
$
|
37,310
|
|
|
$
|
262,358
|
|
|
|
$
|
10,345
|
|
NOTE 5 — RECEIVABLES
Accounts Receivable
|
|
|
|
|
|
|
|
|
(in thousands)
|
March 31, 2019
|
|
December 31, 2018
|
Production and processing sales and fees
|
$
|
48,865
|
|
|
$
|
51,004
|
|
Joint interest billings
|
18,224
|
|
|
18,147
|
|
Pooling interest (1)
|
14,960
|
|
|
18,786
|
|
Allowance for doubtful accounts
|
(113
|
)
|
|
(95
|
)
|
Total accounts receivable, net
|
$
|
81,936
|
|
|
$
|
87,842
|
|
_________________
|
|
(1)
|
Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.
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Related Party Receivables
|
|
|
|
|
|
|
|
|
(in thousands)
|
March 31, 2019
|
|
December 31, 2018
|
Related party receivables
|
$
|
12,197
|
|
|
$
|
12,375
|
|
Allowance for doubtful accounts
|
(9,887
|
)
|
|
(9,034
|
)
|
Related party receivables, net
|
2,310
|
|
|
3,341
|
|
|
|
|
|
Notes receivable from related parties
|
13,403
|
|
|
13,403
|
|
Allowance for doubtful accounts
|
(13,403
|
)
|
|
(13,403
|
)
|
Notes receivable from related parties, net
|
—
|
|
|
—
|
|
Total related party receivables, net
|
$
|
2,310
|
|
|
$
|
3,341
|
|
Management Services Agreement with High Mesa
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.
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 March 31, 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 March 31, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated
with litigation relating to the non-STACK assets. As of March 31, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.
Promissory notes receivable
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 did not pay us on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of March 31, 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 March 31, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.
We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. 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)
|
March 31, 2019
|
|
December 31, 2018
|
Oil and gas properties
|
|
|
|
Unproved properties
|
$
|
69,739
|
|
|
$
|
74,217
|
|
|
|
|
|
Proved oil and gas properties
|
2,163,279
|
|
|
2,110,346
|
|
Accumulated depletion and impairment
|
(1,455,268
|
)
|
|
(1,421,226
|
)
|
Proved oil and gas properties, net
|
708,011
|
|
|
689,120
|
|
Total oil and gas properties, net
|
777,750
|
|
|
763,337
|
|
Other property and equipment
|
|
|
|
Land
|
5,600
|
|
|
5,600
|
|
Fresh water wells
|
27,742
|
|
|
27,366
|
|
Produced water disposal system
|
104,334
|
|
|
104,498
|
|
Gas processing plant and gathering lines
|
396,513
|
|
|
380,470
|
|
Office furniture, equipment and vehicles
|
3,772
|
|
|
3,703
|
|
Accumulated depreciation and impairment
|
(80,997
|
)
|
|
(77,368
|
)
|
Other property and equipment, net
|
456,964
|
|
|
444,269
|
|
Total property and equipment, net
|
$
|
1,234,714
|
|
|
$
|
1,207,606
|
|
Depletion and Depreciation Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Oil and gas properties depletion
|
$
|
34,042
|
|
|
$
|
10,773
|
|
|
|
$
|
11,021
|
|
Midstream tangible asset depreciation
|
3,220
|
|
|
1,122
|
|
|
|
—
|
|
Other property and equipment depreciation
|
408
|
|
|
163
|
|
|
|
609
|
|
Total depletion and depreciation
|
$
|
37,670
|
|
|
$
|
12,058
|
|
|
|
$
|
11,630
|
|
Impairment
During the three months ended March 31, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment of our long-lived assets. Therefore, we did not conduct further analysis on the recognition of additional impairment.
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.
Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10%. The Founder Notes were converted into an equity interest in High Mesa immediately prior to the Business Combination as they were considered part of the non-STACK distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest. Predecessor Period interest on the Founder Notes was $0.1 million.
|
|
|
|
|
|
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
The following summarizes the fair value and classification of our derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 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
|
|
$
|
6,525
|
|
|
$
|
(6,525
|
)
|
|
$
|
—
|
|
Derivatives, long-term assets
|
|
8,182
|
|
|
(7,721
|
)
|
|
461
|
|
Total
|
|
$
|
14,707
|
|
|
$
|
(14,246
|
)
|
|
$
|
461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
11,582
|
|
|
$
|
(6,525
|
)
|
|
$
|
5,057
|
|
Derivatives, long-term liabilities
|
|
9,786
|
|
|
(7,721
|
)
|
|
2,065
|
|
Total
|
|
$
|
21,368
|
|
|
$
|
(14,246
|
)
|
|
$
|
7,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Gain (loss) on derivatives -
|
|
|
|
|
|
|
Oil
|
$
|
(21,669
|
)
|
|
$
|
(21,944
|
)
|
|
|
$
|
4,796
|
|
Natural gas
|
(2,108
|
)
|
|
(67
|
)
|
|
|
1,867
|
|
Total gain (loss) on derivatives
|
$
|
(23,777
|
)
|
|
$
|
(22,011
|
)
|
|
|
$
|
6,663
|
|
Other receivables at March 31, 2019 and December 31, 2018 include $0.3 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month.
We had the following call and put derivatives at March 31, 2019:
OIL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Weighted
|
|
Range
|
Settlement Period and Type of Contract
|
|
in bbls
|
|
Average
|
|
High
|
|
Low
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
137,500
|
|
|
$
|
63.03
|
|
|
$
|
63.03
|
|
|
$
|
63.03
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
2,035,000
|
|
|
66.31
|
|
|
75.20
|
|
|
56.50
|
|
Long Put Options
|
|
2,172,500
|
|
|
53.80
|
|
|
62.00
|
|
|
50.00
|
|
Short Put Options
|
|
2,172,500
|
|
|
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
|
|
279,750
|
|
|
55.00
|
|
|
55.00
|
|
|
55.00
|
|
Short Put Options
|
|
279,750
|
|
|
43.00
|
|
|
43.00
|
|
|
43.00
|
|
NATURAL GAS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume in
|
|
Weighted
|
|
Range
|
Settlement Period and Type of Contract
|
|
MMBtu
|
|
Average
|
|
High
|
|
Low
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
11,030,000
|
|
|
$
|
2.67
|
|
|
$
|
2.72
|
|
|
$
|
2.64
|
|
Basis Swap Contracts
|
|
16,050,000
|
|
|
(0.73
|
)
|
|
(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
|
|
We had the following basis swaps at March 31, 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
|
)
|
13,450,000
|
|
Tex/OKL Panhandle Eastern Pipeline
|
|
NYMEX Henry Hub
|
|
Jan '19
|
|
—
|
|
Dec '19
|
|
(0.70
|
)
|
910,000
|
|
Tex/OKL Panhandle Eastern Pipeline
|
|
NYMEX Henry Hub
|
|
Jan '20
|
|
—
|
|
Mar '20
|
|
(0.49
|
)
|
2,140,000
|
|
San Juan
|
|
NYMEX Henry Hub
|
|
Jan '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.
|
During September 2019, we closed out all open derivative positions with each of our 7 counterparties resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.
NOTE 9 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
|
|
|
|
|
|
|
|
|
(in thousands)
|
March 31, 2019
|
|
December 31, 2018
|
Accounts payable
|
$
|
11,074
|
|
|
$
|
20,422
|
|
|
|
|
|
Accruals for capital expenditures
|
51,951
|
|
|
139,904
|
|
Revenue and royalties payable
|
42,591
|
|
|
50,241
|
|
Accruals for operating expenses
|
18,853
|
|
|
21,830
|
|
Accrued interest
|
15,175
|
|
|
2,477
|
|
Derivative settlements
|
49
|
|
|
109
|
|
Other
|
8,989
|
|
|
12,456
|
|
Total accrued liabilities
|
137,608
|
|
|
227,017
|
|
Accounts payable and accrued liabilities
|
$
|
148,682
|
|
|
$
|
247,439
|
|
NOTE 10 — ASSET RETIREMENT OBLIGATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Balance, beginning of period
|
$
|
11,552
|
|
|
$
|
—
|
|
|
|
$
|
10,469
|
|
Liabilities assumed in Business Combination
|
—
|
|
|
5,998
|
|
|
|
—
|
|
Liabilities incurred
|
313
|
|
|
421
|
|
|
|
—
|
|
Liabilities settled
|
(151
|
)
|
|
(166
|
)
|
|
|
(63
|
)
|
Revisions to estimates
|
—
|
|
|
300
|
|
|
|
63
|
|
Accretion expense
|
229
|
|
|
102
|
|
|
|
39
|
|
Balance, end of period
|
11,943
|
|
|
6,655
|
|
|
|
10,508
|
|
Less: Current portion
|
48
|
|
|
622
|
|
|
|
33
|
|
Long-term portion
|
$
|
11,895
|
|
|
$
|
6,033
|
|
|
|
$
|
10,475
|
|
NOTE 11 — DEBT
|
|
|
|
|
|
|
|
|
(in thousands)
|
March 31, 2019
|
|
December 31, 2018
|
Alta Mesa RBL
|
$
|
278,000
|
|
|
$
|
161,000
|
|
KFM Credit Facility
|
183,000
|
|
|
174,000
|
|
2024 Notes
|
500,000
|
|
|
500,000
|
|
Unamortized premium on 2024 Notes
|
27,892
|
|
|
29,123
|
|
Total debt, net
|
988,892
|
|
|
864,123
|
|
Less: Current portion
|
988,892
|
|
|
690,123
|
|
Long-term debt, net
|
$
|
—
|
|
|
$
|
174,000
|
|
Alta Mesa RBL
In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million, leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated in our discussion of going concern, we and Alta Mesa filed for bankruptcy protection prior to making these payments.
The Alta Mesa RBL has two covenants that are tested quarterly:
|
|
•
|
a ratio of Alta Mesa’s current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and
|
|
|
•
|
a ratio of Alta Mesa’s consolidated debt to its consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0.
|
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against Alta Mesa as a result of an event of default.
KFM Credit Facility
The KFM Credit Facility, as amended, provides for an aggregate committed borrowing capacity of $300.0 million.
There are two maintenance covenants under the KFM Credit Facility that are tested quarterly:
|
|
•
|
a ratio of KFM’s total debt to its consolidated adjusted EBITDA of not greater than 4.5 to 1.0, (which increases to 4.75 after KFM exceeds consolidated EBITDA of $75.0 million) for any 4 quarter period; and
|
|
|
•
|
a minimum interest coverage ratio of KFM’s adjusted EBITDA to interest expense of not less than 2.5 to 1.0.
|
The KFM Credit Facility also limits KFM to holding no more than $15.0 million in cash and limits its ability to award affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.
At March 31, 2019, remaining borrowing capacity under the KFM Credit Facility totaled $117.0 million, however, access to the remaining capacity requires covenant compliance on a pro forma basis for any new borrowings. As discussed above regarding our ability to continue as a going concern and as a result of our and Alta Mesa’s bankruptcy, our only remaining source of liquidity is through our subsidiaries, including KFM. Based on our cash flow needs to meet our financial obligations, we believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020.
2024 Notes
We have estimated the fair value of the 2024 Notes to be $194.9 million at March 31, 2019, which is based on their most recent trading values, which is a Level 1 determination.
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default.
Scheduled Maturities of Debt
|
|
|
|
|
|
Fiscal year
|
|
(in thousands)
|
2019
|
|
$
|
—
|
|
2020
|
|
—
|
|
2021
|
|
—
|
|
2022
|
|
—
|
|
2023
|
|
461,000
|
|
Thereafter
|
|
500,000
|
|
|
|
$
|
961,000
|
|
Based upon our going concern conclusions and the default associated with Alta Mesa’s bankruptcy filing, we believe that our indebtedness under the Alta Mesa RBL and our 2024 Notes should be reported as current liabilities despite their scheduled maturities shown above. We have reported our Alta Mesa RBL debt and our 2024 Notes as current at March 31, 2019. We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the cash collateral agreement approved by the Bankruptcy Court, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.8 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. Accordingly, we have determined that it is appropriate to also report all of our Midstream debt as current at March 31, 2019.
NOTE 12 — COMMITMENTS AND CONTINGENCIES
There have been no material developments during the first quarter of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.
NOTE 13 — SIGNIFICANT CONCENTRATIONS
During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales 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.
ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Revenue marketed by ARM on our behalf
|
$
|
93,391
|
|
|
$
|
41,216
|
|
|
|
$
|
28,757
|
|
|
|
|
|
|
|
|
Marketing and management fees paid to ARM
|
$
|
697
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Fees paid to ARM for services relating to our derivatives
|
193
|
|
|
74
|
|
|
|
66
|
|
Total fees paid to ARM
|
$
|
890
|
|
|
$
|
74
|
|
|
|
$
|
66
|
|
Receivables from ARM for sales on our behalf were $13.0 million and $43.8 million as of March 31, 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 recognized was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
March 31, 2019
|
|
February 9, 2018
Through
March 31, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Stock options
|
$
|
1,239
|
|
|
$
|
1,065
|
|
|
|
$
|
—
|
|
Restricted stock awards
|
1,433
|
|
|
1,233
|
|
|
|
—
|
|
Performance-based restricted stock units
|
7
|
|
|
1,168
|
|
|
|
—
|
|
Total compensation expense
|
$
|
2,679
|
|
|
$
|
3,466
|
|
|
|
$
|
—
|
|
Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year is based on achievement of annual company-specific performance goals and obligations applicable to 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.
The performance targets for the 2019 tranche were established in March 2019 and 572,990 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.
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
David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $36,000 and $28,000 for the period February 9, 2018 through March 31, 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, $970,197 and $28,874 during the 2019 Quarter, the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.
David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $70,180, $112,761 and $67,322 during the 2019 Quarter, the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are included in general and administrative expense.
Bayou City Agreement
In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of March 31, 2019, 61 joint wells have been drilled or spudded. At March 31, 2019 and December 31, 2018, $4.5 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 March 31, 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.
NOTE 16 — BUSINESS SEGMENT INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2019
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
86,363
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
86,363
|
|
Natural gas
|
18,450
|
|
|
—
|
|
|
—
|
|
|
18,450
|
|
Natural gas liquids
|
11,216
|
|
|
—
|
|
|
—
|
|
|
11,216
|
|
Sales of gathered production
|
—
|
|
|
9,560
|
|
|
—
|
|
|
9,560
|
|
Midstream revenue
|
—
|
|
|
22,376
|
|
|
(15,221
|
)
|
|
7,155
|
|
Segment sales revenue
|
116,029
|
|
|
31,936
|
|
|
(15,221
|
)
|
|
132,744
|
|
Other revenue
|
568
|
|
|
7,681
|
|
|
(5,164
|
)
|
|
3,085
|
|
Operating revenue
|
116,597
|
|
|
39,617
|
|
|
(20,385
|
)
|
|
135,829
|
|
Gain on sale of assets
|
1,483
|
|
|
—
|
|
|
—
|
|
|
1,483
|
|
Gain (loss) on derivatives
|
(23,777
|
)
|
|
—
|
|
|
—
|
|
|
(23,777
|
)
|
Total revenue
|
94,303
|
|
|
39,617
|
|
|
(20,385
|
)
|
|
113,535
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating
|
25,108
|
|
|
—
|
|
|
(5,164
|
)
|
|
19,944
|
|
Transportation, processing and marketing
|
17,761
|
|
|
2,063
|
|
|
(15,221
|
)
|
|
4,603
|
|
Midstream operating
|
—
|
|
|
6,151
|
|
|
—
|
|
|
6,151
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
9,695
|
|
|
—
|
|
|
9,695
|
|
Production taxes
|
5,483
|
|
|
—
|
|
|
—
|
|
|
5,483
|
|
Workovers
|
197
|
|
|
116
|
|
|
—
|
|
|
313
|
|
Exploration
|
2,054
|
|
|
—
|
|
|
—
|
|
|
2,054
|
|
Depreciation, depletion, and amortization
|
34,675
|
|
|
3,224
|
|
|
—
|
|
|
37,899
|
|
General and administrative
|
20,947
|
|
|
8,063
|
|
|
508
|
|
|
29,518
|
|
Total operating expenses
|
106,225
|
|
|
29,312
|
|
|
(19,877
|
)
|
|
115,660
|
|
Operating income
|
(11,922
|
)
|
|
10,305
|
|
|
(508
|
)
|
|
(2,125
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
Interest expense
|
(12,830
|
)
|
|
(2,630
|
)
|
|
—
|
|
|
(15,460
|
)
|
Interest income
|
27
|
|
|
4
|
|
|
20
|
|
|
51
|
|
Equity in earnings of unconsolidated subsidiaries
|
—
|
|
|
99
|
|
|
—
|
|
|
99
|
|
Total other income (expense), net
|
(12,803
|
)
|
|
(2,527
|
)
|
|
20
|
|
|
(15,310
|
)
|
Income (loss) from continuing operations before income taxes
|
(24,725
|
)
|
|
7,778
|
|
|
(488
|
)
|
|
(17,435
|
)
|
|
|
|
|
|
|
|
|
Interest expense
|
12,830
|
|
|
2,630
|
|
|
—
|
|
|
15,460
|
|
Depreciation, depletion and amortization
|
34,675
|
|
|
3,224
|
|
|
—
|
|
|
37,899
|
|
Exploration
|
2,054
|
|
|
—
|
|
|
—
|
|
|
2,054
|
|
Loss on unrealized hedges
|
24,142
|
|
|
—
|
|
|
—
|
|
|
24,142
|
|
Equity-based compensation
|
1,661
|
|
|
1,018
|
|
|
—
|
|
|
2,679
|
|
Severance costs
|
3,975
|
|
|
1,896
|
|
|
—
|
|
|
5,871
|
|
Adjusted EBITDAX
|
$
|
54,612
|
|
|
$
|
16,546
|
|
|
$
|
(488
|
)
|
|
$
|
70,670
|
|
|
|
|
|
|
|
|
|
Equity method investment at period end
|
$
|
—
|
|
|
$
|
1,199
|
|
|
$
|
—
|
|
|
$
|
1,199
|
|
Capital expenditures
|
133,077
|
|
|
28,271
|
|
|
—
|
|
|
161,348
|
|
Total assets at period end
|
949,391
|
|
|
446,370
|
|
|
(12,450
|
)
|
|
1,383,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 9, 2018 Through March 31, 2018
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
40,278
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
40,278
|
|
Natural gas
|
5,210
|
|
|
—
|
|
|
—
|
|
|
5,210
|
|
Natural gas liquids
|
4,714
|
|
|
—
|
|
|
—
|
|
|
4,714
|
|
Sales of gathered production
|
—
|
|
|
10,610
|
|
|
(6,737
|
)
|
|
3,873
|
|
Midstream revenue
|
—
|
|
|
7,822
|
|
|
(4,562
|
)
|
|
3,260
|
|
Segment sales revenue
|
50,202
|
|
|
18,432
|
|
|
(11,299
|
)
|
|
57,335
|
|
Other revenue
|
555
|
|
|
—
|
|
|
—
|
|
|
555
|
|
Operating revenue
|
50,757
|
|
|
18,432
|
|
|
(11,299
|
)
|
|
57,890
|
|
Gain on sale of assets
|
5,139
|
|
|
—
|
|
|
—
|
|
|
5,139
|
|
Gain (loss) on derivatives
|
(22,011
|
)
|
|
—
|
|
|
—
|
|
|
(22,011
|
)
|
Total revenue
|
33,885
|
|
|
18,432
|
|
|
(11,299
|
)
|
|
41,018
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Lease operating
|
8,317
|
|
|
—
|
|
|
—
|
|
|
8,317
|
|
Transportation, processing and marketing
|
5,583
|
|
|
2,338
|
|
|
(4,562
|
)
|
|
3,359
|
|
Midstream operating
|
—
|
|
|
587
|
|
|
—
|
|
|
587
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
10,546
|
|
|
(6,737
|
)
|
|
3,809
|
|
Production taxes
|
1,415
|
|
|
—
|
|
|
—
|
|
|
1,415
|
|
Workovers
|
1,245
|
|
|
—
|
|
|
—
|
|
|
1,245
|
|
Exploration
|
1,585
|
|
|
—
|
|
|
—
|
|
|
1,585
|
|
Depreciation, depletion, and amortization
|
11,038
|
|
|
4,641
|
|
|
—
|
|
|
15,679
|
|
General and administrative
|
34,654
|
|
|
2,173
|
|
|
925
|
|
|
37,752
|
|
Total operating expenses
|
63,837
|
|
|
20,285
|
|
|
(10,374
|
)
|
|
73,748
|
|
Operating income
|
(29,952
|
)
|
|
(1,853
|
)
|
|
(925
|
)
|
|
(32,730
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
|
Interest expense
|
(5,196
|
)
|
|
(248
|
)
|
|
—
|
|
|
(5,444
|
)
|
Interest income
|
546
|
|
|
—
|
|
|
—
|
|
|
546
|
|
Total other income (expense), net
|
(4,650
|
)
|
|
(248
|
)
|
|
—
|
|
|
(4,898
|
)
|
Income (loss) from continuing operations before income taxes
|
(34,602
|
)
|
|
(2,101
|
)
|
|
(925
|
)
|
|
(37,628
|
)
|
|
|
|
|
|
|
|
|
Interest expense
|
5,196
|
|
|
248
|
|
|
—
|
|
|
5,444
|
|
Depreciation, depletion and amortization
|
11,038
|
|
|
4,641
|
|
|
—
|
|
|
15,679
|
|
Exploration
|
1,585
|
|
|
—
|
|
|
—
|
|
|
1,585
|
|
Loss on unrealized hedges
|
18,036
|
|
|
—
|
|
|
—
|
|
|
18,036
|
|
Equity-based compensation
|
2,771
|
|
|
42
|
|
|
656
|
|
|
3,469
|
|
Business Combination related expense
|
23,717
|
|
|
—
|
|
|
—
|
|
|
23,717
|
|
Adjusted EBITDAX
|
$
|
27,741
|
|
|
$
|
2,830
|
|
|
$
|
(269
|
)
|
|
$
|
30,302
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
$
|
129,310
|
|
|
$
|
3,745
|
|
|
$
|
—
|
|
|
$
|
133,055
|
|
Total assets at period end
|
2,828,349
|
|
|
1,415,496
|
|
|
(275
|
)
|
|
4,243,570
|
|