ALTA MESA RESOURCES, INC.
The following discussion and analysis should be read in conjunction with the
consolidated financial statements and related notes included elsewhere in this
Annual Report. The following discussion and analysis contains forward-looking
statements that reflect our future plans, estimates, beliefs and expected
performance. The forward-looking statements are dependent upon events, risks and
uncertainties that may be outside our control. Our actual results could differ
materially from those discussed in these forward-looking statements. Factors
that could cause or contribute to such differences include, but are not limited
to, the Buyer's ability and willingness to close the Sale Transactions, the
volatility of oil and gas prices, production timing and volumes, our ability to
continue as a going concern, estimates of proved reserves, operating costs and
capital expenditures, economic and competitive conditions, regulatory changes
and other uncertainties, as well as those factors discussed below and elsewhere
in this Annual Report, all of which are difficult to predict. As a result of
these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur.
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Overview
Alta Mesa Resources, Inc. ("AMR"), together with its consolidated subsidiaries ("we", "us", "our" or "the Company"), is an independent exploration and production company focused on the development of unconventional onshore oil and natural gas reserves in the eastern portion of theAnadarko Basin inOklahoma . 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 theAnadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs.Kingfisher Midstream, LLC ("KFM") conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in theAnadarko Basin that generates revenue primarily through long-term, fee-based contracts.
On
OnJanuary 12, 2020 , KFM and all of its subsidiaries (collectively, the "KFM Debtors") filed voluntary petitions (" KFM Bankruptcy Petitions") for relief under the Bankruptcy Code. OnJanuary 13, 2020 ,SRII Opco GP, LLC and SRII Opco (collectively, the "SRII Debtors" and, together with the KFM Debtors, the "Additional Debtors") filed voluntary petitions ("SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the "Additional Bankruptcy Petitions") for relief under the Bankruptcy Code. The Additional Debtors' Chapter 11 cases are being jointly administered with the Initial Debtors' Chapter 11 cases.
The Initial and Additional Debtors operate their businesses as
"debtors-in-possession" under the jurisdiction of the
OnDecember 31, 2019 , the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated inJanuary 2020 , the "AMH PSA") withBCE-Mach III LLC (the "Buyer") pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of$232.0 million in cash, subject to customary purchase price adjustments (such transaction, the "AMH Sale Transaction"). OnDecember 31, 2019 , the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated inJanuary 2020 , the "KFM PSA" and, together with the AMH PSA, the "PSAs") with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of$88.0 million in cash, subject to customary purchase price adjustments (such transaction, the "KFM Sale Transaction" and, together with the AMH Sale Transaction, the "Sale Transactions"). The Sale Transactions are expected to close no later thanmid-April 2020 , after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries. InMarch 2020 , AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the "AMR Plan"). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH's creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled. The AMR Plan will be subject to approval by theBankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect theBankruptcy Court to hold a hearing to consider confirmation of the AMR Plan inApril 2020 . To the extent that the AMR Plan is confirmed by theBankruptcy Court , AMR expects the AMR Plan to become effective and be consummated shortly thereafter. InMarch 2020 , the KFM Debtors filed a Chapter 11 plan (the "KFM Plan"). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors' estates. Under the KFM Plan, the KFM Debtors will appoint a plan administr 20
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ator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation. The KFM Plan is subject to approval by theBankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors' creditors pursuant to the requirements of the Bankruptcy Code. We expect theBankruptcy Court to hold a hearing to consider confirmation of the KFM Plan inApril 2020 . To the extent that the KFM Plan is confirmed by theBankruptcy Court , KFM expects the KFM Plan to become effective and be consummated shortly thereafter. Additional information relating to the formation of the Company and the acquisition ofAlta Mesa and KFM onFebruary 9, 2018 , may be found in Item 8. Immediately prior to the Business Combination,Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. We have reported these distributed assets as discontinued operations for all periods presented. Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date, including recording the fair values in the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination ("Predecessor Period") and the period after the Business Combination ("Successor Period"). The Company's financial statement presentation reflectsAlta Mesa as the "Predecessor" for periods prior toFebruary 9, 2018 . The Company, including the consolidated results ofAlta Mesa and Kingfisher, is the "Successor" for periods sinceFebruary 9, 2018 . Accordingly, for purposes of explaining our segment results, we have presented the 2019 results with the 2018 Successor Period and the 2018 Predecessor Period results ofAlta Mesa , our Upstream segment. As KFM, our Midstream segment, was acquired onFebruary 9, 2018 , our discussion of our Midstream segment results covers the 2019 results and the 2018 Successor Period results.
Outlook, Market Conditions and Commodity Prices
Our revenue and profitability depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control. Our business has been significantly affected by the price of oil due to its weighting in our production profile.
Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by theOrganization of Petroleum Exporting Countries ; and the value of theU.S. dollar in international currency markets. Commodity prices remain at depressed levels compared to past years, which have had a negative impact on the value of our oil and gas properties and our midstream assets, and the future outlook for prices continues to be unpredictable.
Ability to Continue as a Going Concern
AMR's only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held byAlta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of theBankruptcy Court . The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, "the Debtors") triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed underBankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones. We expect to sell substantially all of our assets no later thanmid-April 2020 . Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.
Delisting fromStock Exchange 21
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As a result of our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended inSeptember 2019 , and they are now traded over the counter under the trading symbols "AMRQQ" and "AMRWQ", respectively. InFebruary 2020 , we filed forms with theSecurities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the "Exchange Act") and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.
Derivatives
We previously operated a hedging program in accordance with requirements under the Alta Mesa RBL. Settlements and fair value changes in our derivatives had significant impacts on our results of operations. Our derivatives were reported at fair value and were sensitive to changes in the price of oil and gas. Changes in derivatives were reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. In connection withAlta Mesa's bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts inSeptember 2019 for net proceeds of approximately$4.0 million . Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. AfterSeptember 2019 , we held no open derivative positions.
For 2019, we recognized a net loss on our derivatives of
Impairments
2019
As noted above, the Initial Debtors filed for bankruptcy protection inSeptember 2019 and the Additional Debtors filed for bankruptcy protection inJanuary 2020 . As a result of our bankruptcy filings and previous restrictions by our lenders on our ability to access additional capital, our ability to incur the levels of spending necessary to continue to develop our upstream properties and expand our midstream operations were significantly restricted. This negatively impacted our future drilling plans and our expectations regarding production levels, which contributed to lower throughput expectations for our midstream processing assets. In addition, the Sale Transactions reflect prices of$232.0 million for substantially all of the upstream properties and assets and$88.0 million for our midstream assets. As these prices were below the carrying value of the respective assets, we adjusted our carrying values down to the expected sales prices, after estimated direct sales costs, as we believe the Buyer has the intent and ability to close the Sale Transactions. Additionally, as a result of the expected sales of our assets described above and our expectations of contracts that will be rejected in bankruptcy, we also recognized impairments of our operating lease right-of-use assets and a long-term prepaid asset due to our inability to recover the carrying value of these assets. 2018 In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of$2.0 billion to our proved and unproved oil and gas properties. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place based on our 2018 drilling results. InMay 2018 , a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation ofCimarron that we accounted for under the equity method.Cimarron's proposed pipeline was to extend from our processing plant toCushing, Oklahoma and was to be constructed and operated byCimarron , which we determined was controlled by the third-party. As the late-2018 outlook forAlta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions toCimarron and elected to abandon the project. We conducted an impairment analysis resulting in the recognition of an impairment charge of$16.0 million during the 2018 Successor Period to reduce the carrying value of our investment inCimarron to its estimated fair value atDecember 31, 2018 . 22
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Based on an estimation of the fair value of KFM utilizing an income approach that took into consideration the late 2018-outlook forAlta Mesa and third-party volumes available for processing, we determined that a portion of the value of KFM's plant and equipment and all of KFM's intangible assets and goodwill were impaired atDecember 31, 2018 . The summary of impairment expense follows (there was no impairment expense during the 2018 Predecessor Period): February 9, 2018 Year Ended December Through (in millions) 31, 2019 December 31, 2018 Impairment attributable to: Upstream Unproved properties $ 31.0 $ 742.1 Proved properties 484.8 1,291.6 Operating lease right-of-use assets 13.3 - Other long-term assets 27.3 - Total Upstream 556.4 2,033.7 Midstream Investment in Cimarron - 16.0 Property and equipment 348.6 68.4 Operating lease right-of-use assets 0.3 - Intangible assets - 395.0 Goodwill - 692.0 Total Midstream 348.9 1,171.4 Total impairment of assets $ 905.3 $ 3,205.1 Results of Operations Business Segments Our discussion of results of operations is presented on a segment basis. Our two reportable segments are (1) Upstream and (2) Midstream, which separately feature distinct revenue producing activities. We evaluate Upstream and Midstream segment performance using Adjusted EBITDAX and Adjusted EBITDA, respectively. The Company's management believes Adjusted EBITDAX and Adjusted EBITDA are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should not be considered as an alternative to our segments' net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies' reports. The Company's applicable corporate activities have also been allocated to the supported business segments.
For the year ended
The tables included below set forth financial information for the year endedDecember 31, 2019 . The 2018 Successor Period and the Predecessor Period are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined 2018 Successor Period fromFebruary 9, 2018 throughDecember 31, 2018 and the Predecessor Period fromJanuary 1, 2018 throughFebruary 8, 2018 as the "2018 Period". 23
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Upstream Segment Results of Operations
Our Upstream segment was impacted by the Business Combination, which caused our 2018 results to be separately presented between Successor and Predecessor Periods. In preparing the following discussion, we have provided a combined total to arrive at a full year 2018 amount and context for the change of such full year amount to the 2019 comparable amount. We view 2018 as a single reporting period since the impact of the Business Combination was limited to the items described below. We believe that this approach:
• allows readers of our financial statements to see how management has
evaluated the operating results; and
• provides readers of our financial statements with adequate context for
their analysis of our operating results.
The impact to our Upstream results following the Business Combination primarily
relates to increased depletion expense associated with a step-up for proved oil
and gas properties and to impairment expense which is associated with the
step-up for both unproved and proved oil and gas properties. We do not believe
that the presentation of full pro forma segment results is more preferable than
the information that follows.
Revenue
Our oil, gas and NGLs revenue varies as a result of changes in commodity prices
and production volumes. The following table summarizes our revenue and
production data for the periods presented:
?
Successor Predecessor
February 9,
2018
Year Ended Through January 1, 2018
December 31, December 31, Through
(in thousands, except per unit data) 2019 2018 February 8, 2018
Net production:
Oil (Mbbl) 5,885 5,053 494
Natural gas (MMcf) 24,802 16,913 1,609
NGLs (Mbbl) 2,760 2,268 151
Total (MBoe) 12,779 10,140 914
Average net daily production volume:
Oil (Mbbld) 16.1 15.4 12.7
Natural gas (MMcfd) 67.9 51.9 41.2
NGLs (Mbbld) 7.6 7.0 3.9
Total (MBoed) 35.0 31.1 23.4
Average sales prices before hedging:
Oil (per bbl) $ 55.79 $ 63.99 $ 62.68
Natural gas (per Mcf) $ 2.16 $ 2.57 $ 2.66
NGLs (per bbl) $ 14.50 $ 18.98 $ 26.41
Revenue
Oil sales $ 328,386 $ 323,299 $ 30,972
Natural gas sales 53,693 43,407 4,276
NGL sales 40,026 43,039 4,000
Total Upstream sales revenue $ 422,105 $ 409,745 $ 39,248
Gain on sale of assets $ 1,488 $ 4,751 $ 840
Oil revenue for 2019 decreased compared to the 2018 Period due to a decrease in
average market prices in 2019, which was partially offset by an increase in
production. The increase in production in 2019 was due to an increase in the
number of wells drilled and new wells on production as a consequence of the
significant 2018 capital expenditure program.
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Table of Contents Index to Financial Statements NGL revenue for 2019 decreased compared to the 2018 Period due to a decrease in average market prices in 2019, which was partially offset by an increase in production. The pricing reduction primarily relates to our election of the treatment of ethane volumes in our contract with KFM. Under our gathering contract with KFM, we have an ability to determine ethane recovery volumes as either a fixed recovery or at the actual levels that the plant can recover. In 2019, we elected to recover ethane volumes at a fixed rate until August, which had the impact of increasing the NGLs volume but decreasing the price received per barrel as the total sales value remained unchanged. Beginning inAugust 2019 , we elected to recover actual ethane volumes. The increase in production volume was primarily due to our 2018 development activities. Gain on sale of assets primarily includes gains from the sale of seismic data in 2019 and the 2018 Period. Successor Predecessor February 9, 2018 January 1, 2018 Year Ended December Through Through (in thousands) 31, 2019 December 31, 2018 February 8, 2018 Gain (loss) on derivatives: Realized gains (losses) - Oil$ 6,858 $ (36,505 ) $ (3,819 ) Natural gas 784 (2,456 ) 1,523 Total realized gains (losses) 7,642 (38,961 ) (2,296 ) Unrealized gains (losses) (19,386 ) 28,714 8,959 Total gain (loss) on derivatives$ (11,744 ) $
(10,247 ) $ 6,663
Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each twelve month period.
In connection with
Operating Expenses
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Successor Predecessor
February 9,
2018
Year Ended Through January 1, 2018
December 31, December 31, Through
(in thousands, except per unit data) 2019 2018 February 8, 2018
Operating expenses:
Lease operating $ 79,884 $ 60,547 $ 4,408
Transportation and marketing 70,324 50,038 3,725
Production taxes 19,455 16,865 953
Workovers 2,652 5,563 423
Exploration 52,354 34,085 7,003
Depreciation, depletion and amortization 120,617 133,554 11,670
Impairment of assets 556,427 2,033,712 -
General and administrative 59,897 114,735 21,234
Total Upstream operating expense $ 961,610 $ 2,449,099 $ 49,416
Select operating expenses per BOE:
Lease operating $ 6.25 $ 5.97 $ 4.82
Transportation and marketing 5.50 4.93 4.08
Production taxes 1.52 1.66 1.04
Workovers 0.21 0.55 0.46
Depreciation, depletion and amortization 9.44 13.17 12.77
Lease operating expense for 2019 increased primarily due to an increase in net
production coupled with the impact of additional costs for produced water
disposal after our asset sale to KFM in the fourth quarter of 2018 and a
non-cash charge to reduce the carrying value of certain supplies to realizable
value.
Transportation and marketing expense for 2019 increased primarily due to increase in net production. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The increase is also due to an increase in committed capacity which went unused during 2019.
Production taxes for 2019 increased primarily due to an increase in production
volumes and an increase in the
Workovers for 2019 decreased primarily due to less workover projects undertaken
due to our efforts to reduce costs. Workovers are associated with maintenance
and other efforts to increase production.
Successor Predecessor
February 9,
2018
Year Ended Through January 1, 2018
December 31, December 31, Through
(in thousands) 2019 2018 February 8, 2018
Exploration expense:
Geological and geophysical costs $ 1,246 $ 6,755 $ 2,440
Exploratory dry hole expense 23 1,954 -
Other exploration expense, including expired
leases 51,010 24,374 4,504
ARO settlements in excess of recorded
liabilities 75 1,002 59
Total exploration expense $ 52,354 $ 34,085 $ 7,003
Exploration expense for 2019 increased primarily due to an increase in expired
and expiring leases, primarily for those in Major and Kingfisher counties in
Oklahoma . Geological and geophysical costs decreased as a result of headcount
reductions.
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Depreciation, depletion and amortization expense for 2019 decreased as a result
of a significantly lower depletable base due to impairments recorded during 2018
and 2019.
Successor Predecessor
February 9,
2018
Year Ended Through January 1, 2018
December 31, December 31, Through
(in thousands) 2019 2018 February 8, 2018
Impairment of assets:
Impairment of unproved properties $ 31,023 $ 742,065 $ -
Impairment of proved properties 484,830 1,291,647 -
Impairment of operating lease right-of-use assets 13,245 - -
Impairment of other long-term assets 27,329 - -
Total impairment of assets $ 556,427 $ 2,033,712 $ -
Impairment of assets for 2019 consisted of impairment of our proved and unproved
properties, operating lease right-of-use assets and a long-term prepaid asset.
Our oil and gas properties were impaired during the third quarter of 2019 based
on our impairment analysis resulting from our bankruptcy filing and further
impaired during the fourth quarter of 2019 after taking into consideration the
expected purchase price of the AMH Sale Transaction, net of estimated direct
costs, for substantially all of our upstream assets. Operating lease
right-of-use assets were impaired during the second quarter 2019 based on our
inability to fully recover cash outflows due to lessors for certain unused
office space. A further impairment of the remaining value of our operating lease
right-of-use assets, as well as significant portion of a long-term prepaid
asset, was taken as of December 31, 2019 , due to the expected sale of
substantially all of our assets and the expected rejection of certain leases and
contracts that indicated we would not be able to fully recover the carrying
value of those assets. We believe the Buyer has the intent and ability to close
the Sale Transactions.
For the 2018 Period, impairment largely related to a decrease in commodity
prices, as well as the results of exploratory and development drilling and well
performance, which reduced the value of our assets. A significant decline in
spot and future estimated commodity prices late in the fourth quarter of 2018,
and the impact of changes in our individual well reserve recovery estimates
triggered a downward revision in the future cash flows expected to be generated
by our oil and gas properties, which required us to reduce the carrying value of
those properties to estimated fair value.
Successor Predecessor
February 9,
2018
Year Ended Through January 1, 2018
December 31, December 31, Through
(in thousands) 2019 2018 February 8, 2018
General and administrative expense:
Employee-related costs $ 22,018 $ 18,203 $ 1,032
Equity-based compensation 5,718 20,000 -
Professional fees 8,289 12,981 1,019
Strategic costs 8,116 - -
Business Combination - 23,717 17,040
Severance costs 4,865 8,357 -
Information technology 4,002 4,654 -
Operating leases 4,193 3,267 208
Provision for uncollectible receivables 1,218 22,438 -
Other 1,478 1,118 1,935
Total general and administrative expense
21,234
General and administrative expense for 2019 decreased compared to the 2018
Period primarily due to (i) nonrecurring expenses in the 2018 Period related to
the Business Combination and professional fees for various advisors, (ii) a
$22.4 million provision for certain related party receivables (including notes
receivable) we assessed as uncollectible, and (iii) higher equity-based
compensation expense and severance costs associated with the departure of
certain members of executive management in late 2018. General and administrative
expense during 2019 also included costs for legal and strategic financial
advisory services associated with financial restructuring activities, including
negotiations with representatives of our lenders and other third
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parties, as well as severance costs associated with a reduction in force in early 2019. All professional fees incurred from the filing of the Initial Bankruptcy Petitions forward, and directly related to the bankruptcy, are reported in Reorganization items, net.
Below is a reconciliation of our loss from continuing operations before income taxes to Upstream Adjusted EBITDAX:
Successor Predecessor
February 9, 2018 January 1, 2018
Year Ended Through Through
(in thousands) December 31, 2019 December 31, 2018 February 8, 2018
Loss from continuing operations before
income taxes $ (597,510 ) $ (2,076,370 ) $ (7,116 )
Interest expense 49,823 38,265 5,511
Depreciation, depletion and amortization 120,617 133,554 11,670
Exploration 52,354 34,085 7,003
Loss (gain) on unrealized hedges 19,386 (28,714 ) (8,959 )
Loss (gain) on sale of property and
equipment - 388 -
Impairment of assets 556,427 2,033,712 -
Equity-based compensation 5,718 20,000 -
Provision for uncollectible related party
receivables(1) 886 22,438 -
Severance costs 4,865 - -
Strategic costs 8,116 - -
Business combination - 23,717 17,040
Non-cash lease operating expense 3,835 - -
Reorganization items, net (449 ) - -
Upstream Adjusted EBITDAX $ 224,068 $ 201,075 $ 25,149
_________________
(1) Represents a provision for the estimated uncollectibility of certain related
party receivables (including notes receivable).
Other (Income) Expense
Successor Predecessor
February 9, 2018 January 1, 2018
Year Ended December Through Through
(in thousands) 31, 2019 December 31, 2018 February 8, 2018
Alta Mesa RBL $ 24,541 $ 2,807 $ 815
2024 Notes 27,453 35,273 3,281
Bond premium amortization (3,432 ) (4,512 ) -
Deferred financing cost amortization 195 221 171
Other 1,066 4,476 1,244
Total interest expense 49,823 38,265 5,511
Interest income (154 ) (1,983 ) (172 )
Reorganization items, net (449 ) - -
Total other (income) expense, net $ 49,220 $ 36,282 $ 5,339
Interest expense for 2019 increased due to higher average debt balances outstanding under the Alta Mesa RBL coupled with higher default and borrowing base deficiency interest rates beginning inSeptember 2019 . We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately$12.0 million throughDecember 31, 2019 . 28
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Table of Contents Index to Financial Statements Reorganization items, net (in thousands) Year Ended December 31, 2019 Unamortized deferred financing fees and premiums $ (24,725 ) Terminated contracts (1,435 ) Legal and other professional advisory fees 25,711 Reorganization items, net $ (449 )
Midstream Segment Results of Operations
Revenue
Our Midstream revenue was primarily derived from product sales, gas gathering
and processing, crude oil gathering, and produced water gathering and disposal
fees.
February 9,
2018
Year Ended Through
December 31, December 31,
(in thousands) 2019 2018
Sales of gathered production $ 37,195 $ 31,506
Midstream revenue 84,763 63,199
Produced water disposal fees 24,988 5,320
Total Midstream revenue $ 146,946 $ 100,025
KFM gas volumes (MMcf) 49,147 35,058
KFM crude oil gas volumes (Mbbls) 1,104 1,739
KFM produced water gathering volumes (Mbbls) 25,295
5,320
Sales of gathered production for 2019 increased compared to the 2018 Successor Period due to increased oil and gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. We process the gas on behalf of the producer and sell the resulting gas, condensate and NGLs at a market price. Product sales are recognized when sold to the third-party purchaser. Amounts recognized in product sales are dependent on whether we are acting in the role of a principal or agent in our contracts with our customers. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. Midstream revenue for 2019 increased compared to the 2018 Successor Period due to increased gas gathering volumes and the impact of a second cryogenic processing train commissioned in mid-2018. The level of drilling and well completion activity of our customers impacts the fees we earn from the throughput of gas we gather and process and the volume of crude oil we gather each period. Produced water disposal fees resulted from the acquisition of produced water disposal assets fromAlta Mesa during the fourth quarter of 2018. The level of drilling and well completion activity of our customers impacts the amount of fees we generate from the produced water that we gather and dispose of. 29
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Expenses
February 9,
2018
Year Ended Through
December 31, December 31,
(in thousands) 2019 2018
Midstream operating $ 24,719 $ 15,221
Cost of sales for purchased gathered production 34,529 31,247
Transportation and processing 9,659 9,911
Workovers 537 -
Depreciation and amortization 11,675 27,388
Impairment of assets:
Impairment of Cimarron investment - 15,963
Impairment of property and equipment 348,597
68,407
Impairment of operating lease right-of-use assets 269 - Impairment of intangible assets -
394,999
Impairment of goodwill -
691,970
Total Midstream impairment of assets 348,866
1,171,339
General and administrative 35,427 14,025 Total operating expenses$ 465,412 $ 1,269,131 Midstream operating expense for 2019 increased compared to the 2018 Successor Period due to operating expenses for the produced water disposal assets acquired fromAlta Mesa during the fourth quarter of 2018 and the impact of higher volumes processed, which led to higher variable plant operating costs. Cost of sales for purchased gathered production for 2019 increased compared to the 2018 Successor Period due to increase in sales of gathered production. The margin for net sales increased due to plant efficiency improvements during 2019. Depreciation and amortization expense for 2019 decreased compared to the 2018 Successor Period due to amortization expense related to intangible customer relationship assets that were fully impaired atDecember 31, 2018 . This impact was coupled with a decrease in tangible asset depreciation as a result of significantly lower book asset values due to impairments recorded during 2018 and 2019, partially offset by depreciation on the produced water assets acquired in the fourth quarter of 2018. Impairment of assets for 2019 decreased compared to the 2018 Successor Period. During 2019, property and equipment was impaired during the third quarter of 2019 as a result of our impairment analysis arising from the bankruptcy filing byAlta Mesa . We further impaired these assets during the fourth quarter 2019, after taking into consideration the expected purchase price of the KFM Sale Transaction, net of estimated direct costs, for substantially all of our assets. We believe the Buyer has the intent and ability to close the Sale Transactions. During the 2018 Successor Period, impairment of assets consisted of write-downs of our equity method investment inCimarron , certain property and equipment and full write-offs of the carrying amount of our intangible assets and goodwill. The fair value of the Midstream segment was negatively impacted by a significant decline in commodity prices in the fourth quarter of 2018 and the related impact on our and other producers' future upstream operating plans. Our upstream operations contribute a significant portion of the volumetric throughput to the KFM plant. A decline in such throughput negatively impacts future expected profitability, and thus, fair value of the Midstream segment.
We reduced the carrying amount of our investment in
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February 9,
2018
Year Ended Through
December 31, December 31,
(in thousands) 2019 2018
General and administrative expenses:
Employee-related costs $ 14,569 $ 8,199
Equity-based compensation 694 1,190
Professional fees 2,092 1,743
Strategic costs 11,479 10
Severance costs 2,162 -
Information technology 214 240
Operating leases 348 253
Provision for uncollectible receivable 2,310 -
Other 1,559 2,390
Total general and administrative expense$ 35,427
General and administrative expense for 2019 increased compared to the 2018 Successor Period primarily due to increased employee-related costs allocable to KFM, increased costs for legal and strategic financial advisory services associated with financial restructuring activities, and a provision to fully reserve a receivable from KFM's former owner due to our assessment regarding collectibility. Moreover, following a reassessment of 2019 activity levels, we implemented a reduction in force program during 2019, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.
Below is a reconciliation of our loss from continuing operations before income taxes to Midstream Adjusted EBITDA:
February 9, 2018
Year Ended Through
(in thousands) December 31, 2019 December 31, 2018
Loss from continuing operations before income taxes $ (323,975 ) $ (1,174,131 )
Interest expense 11,636 5,031
Depreciation and amortization 11,675 27,388
Loss on sale of property and equipment 106 -
Impairment of assets 348,866 1,171,339
Equity-based compensation 694 1,190
Severance costs 2,162 -
Strategic costs 11,479 -
Provision for uncollectible related party receivables 2,310 -
Gain on equity method investment (5,503 ) -
Adjusted EBITDA $ 59,450 $ 30,817
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Other Income (Expense)
February 9, 2018
Year Ended December Through
(in thousands) 31, 2019 December 31, 2018
KFM Credit Facility $ 10,728 $ 3,062
Deferred financing cost amortization 463 305
Other 445 1,664
Total interest expense 11,636 5,031
Interest income (17 ) (6 )
Equity in earnings of unconsolidated subsidiaries (6,216 ) -
Total other (income) expense $ 5,403 $ 5,025
Interest expense for 2019 increased primarily due to higher average debt balances outstanding under the KFM Credit Facility. Other interest primarily relates to commitment fees.
Equity in earnings of unconsolidated subsidiaries represents our share of earnings due to our equity method investment inCimarron . InNovember 2019 , we obtained control ofCimarron . As a result, we recognized a gain of$5.5 million to adjust our investment to the fair value of the assets to be received upon consolidating this entity.
Liquidity and Capital Resources
Our principal requirements for capital are to fund our day-to-day operations and to satisfy our contractual obligations. During 2019, our main sources of liquidity and capital resources came from cash on hand, operating cash flow and borrowings under the Alta Mesa RBL and KFM Credit Facility. OnSeptember 11, 2019 , the Initial Debtors filed for bankruptcy protection, which constituted an event of default under the Alta Mesa RBL that acceleratedAlta Mesa's obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default. As ofDecember 31, 2019 , we had$355.9 million in outstanding borrowings under the Alta Mesa RBL, plus$1.9 million in outstanding letters of credit. InAugust 2019 , our lenders elected to exercise their right to an off-cycle borrowing base redetermination, whereby they reduced our borrowing base from$370.0 million to$200.0 million . As a condition to the borrowing base reduction, we were required to make monthly installments of$32.5 million for five months, beginning inSeptember 2019 , to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments. Subsequent toAlta Mesa's bankruptcy filing, we began operating under a cash collateral order issued by theBankruptcy Court that allowsAlta Mesa to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations. OnSeptember 23, 2019 , KFM received a reservation of rights letter from its lenders asserting an event of default under the KFM Credit Agreement, thereby eliminating its ability to access capital under its revolver, pending a cure of the alleged event of default. As a result, KFM utilized cash on hand and cash flow from operations to fund required expenditures and satisfy contractual obligations during the fourth quarter 2019. OnJanuary 12, 2020 , the KFM Debtors filed for bankruptcy protection under Chapter 11 of the bankruptcy code, which constituted an event of default under the KFM Credit Facility that accelerated KFM's obligations thereunder. Under the Bankruptcy Code, the lenders under the KFM Credit Facility are stayed from taking any action against the KFM Debtors as a result of an event of default. As ofDecember 31, 2019 , outstanding borrowings under the KFM Credit Facility totaled$224.0 million and there were no outstanding letters of credit. Subsequent to KFM's bankruptcy filing, we began operating under a cash collateral order issued by theBankruptcy Court that allows KFM to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.
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e Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.
2024 NotesAlta Mesa has$500.0 million in aggregate principal amount of outstanding notes bearing interest at 7.875% per annum, payable semi-annually eachJune 15 andDecember 15 . The 2024 Notes mature inDecember 2024 .Alta Mesa's filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that acceleratedAlta Mesa's obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action againstAlta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately$12.0 million throughDecember 31, 2019 .
Related Party Receivables
OnSeptember 29, 2017 ,Alta Mesa entered into a$1.5 million promissory note receivable with its affiliateNorthwest Gas Processing, LLC , which obligation was subsequently transferred toHigh Mesa Services, LLC ("HMS"), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured onFebruary 28, 2019 . AtDecember 31, 2019 and 2018, amounts due under the promissory note totaled$1.7 million . HMS defaulted under the terms of that promissory note when it was not paid when due onFebruary 28, 2019 , and HMS has failed to cure such default.Alta Mesa subsequently declared all amounts owing under the note immediately due and payable.Alta Mesa also has an$8.5 million promissory note receivable from HMS which matures onDecember 31, 2019 , and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As ofDecember 31, 2019 , and 2018, the note receivable amounted to$11.7 million . HMI disputes its obligations under the$1.5 million note and$8.5 million note referenced above as payable toAlta Mesa . We oppose HMI's claims and believe HMI's obligation under the notes to be valid assets ofAlta Mesa and that the full amount is payable toAlta Mesa . We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. We believe there is substantial doubt about HMI's ability to make payment and honor its indemnification, which is further complicated by HMI's filing for bankruptcy protection inJanuary 2020 . As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As ofDecember 31, 2019 , we established an allowance for doubtful accounts for the promissory notes totaling$13.4 million , the expense for which is included in general and administrative expense in 2018. Interest income on the promissory notes amounted to approximately$0.9 million and$0.1 million for the 2018 Successor Period and the 2018 Predecessor Period, respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019. In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the "HMI Agreement") with HMI with respect to its non-STACK assets. Under the HMI Agreement, during the 180-day period following the Closing (the "Initial Term"), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the "Services"). Thereafter, the HMI Agreement automatically renewed for additional consecutive 180-day periods (each a "Renewal Term"), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of$10,000 , (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services. Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the HMI Agreement effectiveJanuary 31, 2019 . ThroughApril 1, 2019 , we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services fromAlta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the HMI Agreement. Prior to 2018, we also incurred$0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement as "Receivables due from related party" in the balance sheets. As ofDecember 31, 2019 andDecember 31, 2018 , we had receivables of approximately$9.8 million and$10.1 million for costs and expenses incurred on HMI's behalf. Subsequent to 33
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year-end 2018, we billed HMI$0.8 million for incremental MSA costs incurred and have received approximately$1.1 million in payments. HMI has disputed certain of these amounts billed byAlta Mesa . We are pursuing remedies under applicable law in connection with repayment of this receivable. We believe there is substantial doubt about HMI's ability to make payment and honor its indemnification, which is further complicated by HMI's filing for bankruptcy protection inJanuary 2020 . As a result, as ofDecember 31, 2019 , we have recognized an allowance for uncollectible accounts of$9.8 million to fully provide for the unremitted balance. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings. Tax Receivable Agreement We are party to a Tax Receivable Agreement ("TRA") with SRII Opco, High Mesa, andRiverstone VI Alta Mesa Holdings, L.P. This agreement generally provides for the payment by us of 85% of the amount of any realized net cash savings, inU.S. federal, state and local income tax in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by KFM or otherwise used in KFM's midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. Also, under the TRA, we retain the benefit of the remaining 15% of these cash savings. As ofDecember 31, 2019 , there had been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred inNovember 2018 when 2,752,312 SRII Opco Common Units then held by High Mesa were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash savings inU.S. federal, state and local income tax, multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as ofDecember 31, 2019 , we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have not recorded a liability for such at this time. As a result of our bankruptcy filings and the expected sale of substantially all of our assets, we do not anticipate any payments being required under the TRA. Cash Flows Successor Predecessor February 9, 2018 January 1, 2018 Year Ended December 31, Through Through (in thousands) 2019 December 31, 2018 February 8, 2018 Cash from operating activities $ 143,798 $ 86,809 $ 26,336 Cash from investing activities (320,329 ) (560,547 ) (37,913 ) Cash from financing activities 244,724 501,205 16,932 Net increase in cash, cash equivalents and restricted cash $ 68,193 $ 27,467 $ 5,355
Cash from operating activities
Cash provided by operating activities during 2019 increased compared to the 2018 Successor Period and the 2018 Predecessor Period primarily due to collection of receivables, which were higher atDecember 31, 2018 as compared toDecember 31, 2019 due to our bankruptcy filing. Additionally, our 2018 operating cash flow was burdened by nonrecurring costs associated with (i) certain administrative services provided to HMI and its subsidiaries that were subsequently determined to be uncollectible and (ii) the Business Combination. Partially offsetting these factors was an increased use of cash in 2019 associated with prepayment of legal and professional advisor fees relating to our bankruptcy filing as well as a prepayment of transportation fees under a long-term customer contract. 34
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Cash from investing activities
Cash used in investing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period, primarily due to significantly reduced capital expenditures resulting from the suspension of our development activities in conjunction withAlta Mesa's bankruptcy filing inSeptember 2019 . The 2018 Successor Period included activity relating to the Business Combination, which was funded through proceeds withdrawn from a trust account that was established upon the initial public offering of the Company in 2017.
Cash from financing activities
Cash provided by financing activities during 2019 decreased compared to the 2018 Successor Period and the 2018 Predecessor Period. Our ability to borrow funds during 2019 was terminated uponAlta Mesa's bankruptcy filing inSeptember 2019 and restrictions imposed by the lenders under the KFM Credit Facility due to an alleged default. During the 2018 Successor Period, we received$400.0 million from the sale of our Class A Common Stock and warrants pursuant to a forward purchase agreement, which was partially offset by deferred underwriting payments and certain other costs associated with the Business Combination plus repurchases of our common stock. Risk Management Activities - Commodity Derivative Instruments In connection withAlta Mesa's bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts inSeptember 2019 for net proceeds of approximately$4.0 million . Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. AfterSeptember 2019 , we held no open derivative positions.
Off-Balance Sheet Arrangements
As ofDecember 31, 2019 , other than as described below, we had no guarantees of third-party obligations.Alta Mesa was contingently liable for bonds posted in the aggregate amount of$1.3 million , primarily to cover future abandonment costs, and$1.9 million in letters of credit provided under the Alta Mesa RBL. Upon closing of the expected Sale Transactions, we would be released from these obligations. We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.Alta Mesa and HMI are both parties to a payment and indemnity agreement with our current surety provider in connection with regulatory bonds executed prior to the Business Combination covering STACK and non-STACK assets. The surety bonds in place covered by the payment and indemnity agreement for HMI non-STACK properties total approximately$15 million . The surety asserts thatAlta Mesa is jointly and severally liable pursuant to the payment and indemnity agreement, butAlta Mesa disputes that claim asserting that the Business Combination evidenced separation between the STACK and non-STACK assets thereby removing any exposure ofAlta Mesa to liabilities associated with non-STACK assets. As a result of the dispute, the surety has filed liens onAlta Mesa and KFM assets in order to establish a claim againstAlta Mesa in the event HMI is unable to post collateral or otherwise satisfy its obligations with respect to the surety bonds. The closing of the expected Sale Transactions is not expected to impact these outstanding surety bonds.
Critical Accounting Policies and Estimates
Our financial statements are prepared in accordance with GAAP. In connection with preparing our financial statements, we are required to make assumptions and estimates about future events and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in our audited financial statements included elsewhere in this Annual Report. We believe that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.
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Oil and Gas Reserves Policy Description Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In calculating cash inflows for reserves, we use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling. In calculating cash outflows for reserves, we use well costs and operating costs prevailing during the preceding year, but more heavily weighted toward recent demonstration levels, which are then held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental policies.
We limit our future development program to only those wells that we expect to be developed within five years of their initial recognition.
Judgments and Assumptions
All of our reserve information is based on estimates. Estimates of gas reserves are prepared in accordance with guidelines established by theSEC . Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil and gas. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. We have used estimates of proved reserves in the past to assess for impairment, and we also rely heavily on them in the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate and resulting expense will increase, resulting in a decrease in net income. A decline in estimates of proved reserves have also caused us in previous periods to perform an impairment analysis to determine whether the carrying amount of oil and gas properties exceeds fair value, which would result in an impairment charge, reducing net income. Successful Efforts Method of Accounting forOil and Gas Properties
Policy Description
Oil and gas producing activities are accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Accounting policies include:
Unproved Properties - Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts incurred to obtain a mineral interest or right in a property, such as a lease, options to lease, and related broker and other fees. Properties are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire or are sold.Proved Oil and Gas Properties - Costs incurred to lease, drill, complete and equip proved reserves are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized. Impairment - Our unproved properties consist of leasehold and other capital costs incurred for properties for which no proved reserves have been identified. In determining whether unproved property is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists' evaluation of the property and the remaining 36
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lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated resource potential and, combined with a market approach, estimate fair value of our properties. Our cash flow estimates for probable and possible resource potential is reduced by additional risk-weighting factors. We then reduce the carrying amount of unproved properties, if higher, to estimated fair value. The capitalized costs of proved oil and gas properties are reviewed at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level or the likely cash flow from sale of the assets to the carrying value of the assets. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value. For our proved oil and gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
Judgments and Assumptions
Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. Key assumptions used to determine the undiscounted future cash flows could include estimates of future production, timing of new wells coming on line, differentials, net estimated operating costs, anticipated capital expenditures and future commodity prices. Our discussion of the judgments inherent in reserve estimation above has information with direct bearing on the judgments surrounding our depletion calculation and impairment analysis. However, in conducting our impairment analysis, we also replace pricing assumptions with future price estimates and we include values for our probable and possible resource potential in determining fair value. Lower net undiscounted cash flows can result in the carrying amount of our oil and gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in levels and timing of capital and operating expenses, and changes in production among other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly which can negatively impact forward commodity prices, causing lower undiscounted net cash flows. Similarly, future capital and lease operating costs are uncertain and can change quickly based on regional oil and gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, among other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans. Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.
Recent Accounting Pronouncements
Our audited financial statements in Item 8 contain a description of recent accounting pronouncements.
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