NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization and basis of presentation
Unless the context requires otherwise, references in this Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” the “Company,” “we,” “our” and “us” are to EXCO Resources, Inc. and its consolidated subsidiaries.
We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions:
•
East Texas and North Louisiana
The East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with a wholly owned subsidiary of Royal Dutch Shell, plc (“Shell”), covering an undivided
50%
interest in the majority of our Haynesville and Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions.
•
South Texas
The South Texas region is primarily comprised of our Eagle Ford shale assets. We serve as the operator for most of our properties in the South Texas region.
•
Appalachia
The Appalachia region is primarily comprised of our Marcellus shale assets. We had a joint venture with Shell covering our Marcellus shale and other assets in the Appalachian region (“Appalachia JV”). EXCO and Shell each owned an undivided
50%
interest in the Appalachia JV and a
49.75%
working interest in the Appalachia JV’s properties. The remaining
0.5%
working interest is held by an entity that operates the Appalachia JV’s properties (“OPCO”), which was previously jointly owned by EXCO and Shell. On February 27, 2018, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in the Appalachia JV and OPCO. See further discussion of this transaction in “
Note 3. Acquisitions, divestitures and other significant events
”.
The accompanying Consolidated Balance Sheets as of
December 31, 2018
and
2017
, Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the
years ended December 31, 2018 and 2017
are for EXCO and its consolidated subsidiaries. The Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.
Chapter 11 Cases and Going Concern Assessment
On January 15, 2018 (“Petition Date”), the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP and Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Court”). The cases are being jointly administered under the caption
In Re EXCO Resources, Inc., Case No. 18-30155 (MI)
(“Chapter 11 Cases”). The Court granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 Cases on their operations, customers and employees. The Debtors continue to operate their businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. The Debtors expect to continue operations without interruption during the pendency of the Chapter 11 Cases.
For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 Cases. As a result of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this annual report on Form 10-K may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases.
The outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and creditors. The significant risks and uncertainties related to our liquidity and the Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. We define liquidity as cash and restricted cash plus the unused borrowing base under the debtor-in-possession credit agreement (“Liquidity”). These Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.
Chapter 11 filing impact on creditors and shareholders
The Debtors filed schedules and statements with the Court setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements are subject to further amendment or modification during the Chapter 11 Cases. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by April 15, 2018. The deadline for governmental units to file proofs of claim was September 4, 2018. Differences between amounts scheduled by the Debtors and claims by creditors are being investigated and will be reconciled and resolved to within an immaterial amount in connection with the claims resolution process. In light of the number of creditors with filed or scheduled claims, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently asserted.
Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition and post-petition liabilities owed to creditors must be satisfied in full before the holders of our existing common shares are entitled to receive any distributions or retain any property under a plan of reorganization. The ultimate recovery for creditors and shareholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors or shareholders may receive.
Automatic stay
Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial and administrative actions against the Debtors as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are stayed.
Impact on indebtedness
As of the Petition Date, we had approximately
$1.4 billion
in principal amount of indebtedness, including approximately: (i)
$126.4 million
outstanding under our previous revolving credit agreement (“EXCO Resources Credit Agreement”), (ii)
$317.0 million
outstanding under our senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), (iii)
$708.9 million
outstanding under our senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), (iv)
$17.2 million
outstanding under our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), (v)
$131.6 million
outstanding under our senior unsecured notes due September 15, 2018 (“2018 Notes”), and (vi)
$70.2 million
outstanding under our senior unsecured notes due April 15, 2022 (“2022 Notes”). The commencement of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:
|
|
•
|
EXCO Resources Credit Agreement;
|
These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As a result of the Chapter 11 Cases, the Court may limit post-petition interest on debt that may be under-secured or unsecured.
On January 22, 2018, we closed a debtor-in-possession credit agreement (“DIP Credit Agreement”) with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”). The DIP Credit Agreement includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of
$125.0 million
(“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of
$125.0 million
(“Revolver B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). Proceeds from the DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 Cases. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.
As of December 31, 2018
, we had
$156.4 million
in outstanding indebtedness and
$81.6 million
of available borrowing capacity under the DIP Facilities. On January 15, 2019, we entered into an amendment to the DIP Credit Agreement to extend the maturity date from January 22, 2019 to May 22, 2019. See further discussion of the DIP Credit Agreement in “
Note 5. Debt
”.
Restrictions on trading of our equity securities to protect our use of net operating losses
The Court has entered a final order pursuant to Sections 362(a)(3) and 541 of the Bankruptcy Code enabling the Company and the Filing Subsidiaries to avoid limitations on the use of our income tax net operating loss carryforwards (“NOLs”) and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of our outstanding common shares (“Substantial Shareholder”), and requires that each Substantial Shareholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person or entity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.
Executory contracts
Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Debtors for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance thereunder. Any description of the treatment of an executory contract or unexpired lease with the Company or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights they have with respect to executory contracts and unexpired leases under the Bankruptcy Code.
During March 2018, the Court approved the rejection of the following executory contracts:
|
|
•
|
Firm transportation agreements with Acadian Gas Pipeline System, which required us to transport
325,000
Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025;
|
|
|
•
|
Natural gas sales agreements with Enterprise Products Operating LLC (“Enterprise”), which required us to sell
75,000
Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025;
|
|
|
•
|
Firm transportation agreements with Regency Intrastate Gas Systems LLC, which required us to either transport
237,500
Mmbtu per day of natural gas or pay reservation charges through January 31, 2020;
|
|
|
•
|
Marketing agreement with a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), which required us to allow Chesapeake to purchase natural gas from certain wells in North Louisiana through 2021; and
|
|
|
•
|
Natural gas sales agreements with Shell, which required us to sell
100,000
Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020.
|
On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018. The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding (Adv. Proc. No. 18-03096) against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties. The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. On November 19, 2018, the Court approved an agreement entered into by EXCO and Azure to settle any claims related to the minimum volume commitment (“Azure Settlement Agreement”). Per the terms of the Azure Settlement Agreement:
|
|
•
|
EXCO agreed to pay Azure
$15.0 million
and transfer equity interests held in Azure (~3.35%) on the effective date of EXCO’s plan of reorganization; and
|
|
|
•
|
EXCO will assume the base gathering agreement with Azure and cure any associated pre-petition amounts associated with the agreement on or before February 28, 2019.
|
Upon completion of the aforementioned criteria, Azure’s claims related to the base gathering agreement and minimum volume commitment will be deemed to be satisfied. On March 1, 2019, we paid
$6.4 million
of pre-petition costs for gathering services under the base gathering agreement. The remaining payment and transfer of equity interests are expected to be paid on the effective date of EXCO's plan of reorganization.
As of December 31, 2018, the accrual of
$30.3 million
related to the minimum volume commitment was classified as “Liabilities subject to compromise” and the equity interests in Azure of
$0.8 million
were classified as "Equity investments" on our Consolidated Balance Sheet. The impact of the Azure Settlement Agreement will not be reflected in the financial statements until all material contingencies are resolved, including the payments and transfer of equity interests that are expected to occur on the effective date of the plan of reorganization.
On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022.
Plan of Reorganization
On October 1, 2018, the Debtors filed a Settlement Joint Chapter 11 Plan of Reorganization (the “October 2018 Plan”) and related Disclosure Statement with the Court. As is customary in bankruptcy proceedings, the Debtors subsequently filed amendments to the October 2018 Plan and related Disclosure Statement with the Court. The distributions under the October 2018 Plan were expected to be funded with: (i) cash on hand; (ii) a new revolving credit facility; (iii) a new second lien debt instrument; (iv) the equity in the reorganized Company; and, (v) the D&O Proceeds, as defined below.
On November 5, 2018, the Court authorized us to solicit acceptances of the October 2018 Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the October 2018 Plan. Simultaneous with the solicitation process, we initiated a marketing process for the issuance of the new revolving credit facility and the new second lien debt instrument. During the course of the marketing process, oil prices experienced a significant decline and overall market conditions worsened. As a result, we were not able to obtain the exit financing required to consummate the October 2018 Plan. On February 15, 2019, the Court approved a motion to extend the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019.
On March 8, 2019, the Debtors filed a Second Amended Joint Chapter 11 Plan of Reorganization (“March 2019 Plan”) and related Disclosure Statement with the Court. The March 2019 Plan provides for either a reorganization of the Debtors as a going concern or the sale of the Debtors’ assets (“All Asset Sale”). The Debtors will make a final determination regarding which path to pursue by the date of the hearing to approve the Disclosure Statement. The March 2019 Plan included the following key elements:
|
|
•
|
Holders of the DIP Credit Agreement will receive payment in full in cash with proceeds from either a new revolving credit facility (“Exit Facility”) or, in the event of an All Asset Sale, proceeds from the sale of assets;
|
|
|
•
|
Holders of allowed 1.5 Lien Notes claims will receive either their pro rata share of a new mandatorily convertible security or, in the event of an All Asset Sale, the liens securing such allowed claim;
|
|
|
•
|
Holders of allowed 1.75 Lien Term Loans claims will receive either their pro rata share of the equity in the reorganized Company representing the value attributable to encumbered assets or, in the event of an All Asset Sale, the liens securing such allowed claim;
|
|
|
•
|
Holders of the Second Lien Term Loans, 2018 Notes, 2022 Notes, allowed general unsecured claims and deficiency claims associated with the 1.75 Lien Term Loans will receive either their pro rata share of equity in the reorganized Company representing the value attributable to unencumbered assets, or in the event of an All Asset Sale, proceeds attributable to the sale of the unencumbered assets (“Unsecured Claims Recovery”);
|
|
|
•
|
Holders of existing equity interests in EXCO shall not receive a distribution and the equity interests will be deemed canceled, discharged, released and extinguished; and
|
|
|
•
|
The carriers of directors’ and officers’ liability insurance coverage related to the Debtors will contribute
$13.4 million
(“D&O Proceeds”) to the Debtors in exchange for full and final settlement of potential claims and causes of action against current and former directors and officers.
|
The March 2019 Plan does not release the Debtors or holders of claims of the 1.5 Lien Notes and 1.75 Lien Term Loans from certain causes of action. The litigation of these causes of action will be managed by a trustee appointed by the committee of unsecured creditors of the Debtors and will not occur until after the confirmation of the March 2019 Plan. If any of the disputed claims are successfully prosecuted, this could materially impact the aforementioned recoveries for holders of allowed claims. If some or all of the 1.5 Lien Notes claims or 1.75 Lien Term Loans claims are deemed to be unsecured claims following the successful prosecution of a secured claims challenge, the holders of such 1.5 Lien Notes claims and 1.75 Lien Term Loans claims will receive their pro rata share of the Unsecured Claims Recovery.
We have not received consents from any creditors in support of the March 2019 Plan. Therefore, we may not receive the requisite acceptances to confirm the March 2019 Plan. Even if the requisite acceptances for the March 2019 Plan are received, the Court may not confirm such a plan. Therefore, we are not able to predict or quantify the ultimate impact that events occurring during the Chapter 11 cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 cases may have on our corporate or capital structure.
Accounting during bankruptcy
We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852,
Reorganizations
(“ASC 852”), in the preparation of these Consolidated Financial Statements. For periods subsequent to the Chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that have been approved for rejection by the Court, and adjustments to the carrying value of certain indebtedness are recorded as “Reorganization items, net” on the Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Consolidated Balance Sheet as of
December 31, 2018
as “Liabilities subject to compromise.”
Liabilities subject to compromise
The accompanying Consolidated Balance Sheet as of
December 31, 2018
includes amounts classified as liabilities subject to compromise, which represent liabilities that are anticipated to be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.
Liabilities subject to compromise include amounts related to the rejection of various executory contracts and unexpired leases. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts or unexpired leases are rejected. Conversely, to the extent that executory contracts or unexpired leases are not rejected and are instead assumed, liabilities associated therewith would constitute post-petition liabilities which will be satisfied in full under a plan of reorganization. The nature of certain potential claims arising under the Debtors’ executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material.
The following table summarizes the components of liabilities subject to compromise included on the Consolidated Balance Sheet as of
December 31, 2018
:
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2018
|
Current maturities of long-term debt
|
|
$
|
927,917
|
|
Accrued interest payable
|
|
34,281
|
|
Accounts payable, accrued expenses and other liabilities
|
|
95,915
|
|
Liabilities related to rejected executory contracts
|
|
385,370
|
|
Liabilities subject to compromise
|
|
$
|
1,443,483
|
|
As of
December 31, 2018
, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimates of the recoverability of claims related to these instruments.
Reorganization items, net
We have incurred significant expenses associated with the Chapter 11 process, primarily (i) the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60,
Troubled Debt Restructuring by Debtor
s, (ii) adjustments for estimated allowable claims related to executory contracts approved for rejection by the Court, and (iii) legal and professional fees incurred subsequent to the Petition Date related to the restructuring process. These costs, which are being expensed as incurred, significantly impact our results of operations. The following table summarizes the components included in “Reorganization items, net” in our Consolidated Statement of Operations for
the year ended December 31, 2018
:
|
|
|
|
|
|
(in thousands)
|
|
Year Ended December 31, 2018
|
Legal and professional fees
|
|
$
|
67,790
|
|
Deferred financing costs, debt discounts and deferred reductions in carrying value
|
|
30,509
|
|
Rejection of executory contracts
|
|
312,182
|
|
Other
|
|
(1,183
|
)
|
Reorganization items, net
|
|
$
|
409,298
|
|
As of December 31, 2018, our accrual of
$24.9 million
for legal and professional fees related to the Chapter 11 Cases incurred subsequent to the Petition Date was classified as "Accounts payable and accrued liabilities" on our Consolidated Balance Sheet. Our cash disbursements for reorganization items for
the year ended December 31, 2018
were
$43.0 million
.
Interest expense
We have discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest on liabilities subject to compromise not reflected in the Consolidated Statement of Operations was approximately
$103.6 million
, representing interest expense from the Petition Date through
December 31, 2018
. The cash interest rate of
12.5%
was utilized in the determination of contractual interest expense that would have been incurred under the 1.75 Lien Term Loans for the period subsequent to the Petition Date.
2.
Significant accounting policies
We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. In addition, see further discussion of our application of ASC 852 as a result of the Chapter 11 Cases in “
Note 1. Organization and basis of presentation
”.
Principles of consolidation
We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of
December 31, 2018
and
2017
and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the
years ended December 31, 2018 and 2017
. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated.
Management estimates
In preparing the Consolidated Financial Statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates.
Cash equivalents
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Restricted cash
The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with Shell that is used to fund our share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana.
Concentration of credit risk and accounts receivable
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both
December 31, 2018
and
2017
. We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.
For the year ended
December 31, 2018
, sales to Chesapeake Energy Marketing, Inc. and CIMA Energy, LTD accounted for approximately
17%
and
15%
, respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake") and CIMA Energy, LTD is a subsidiary of Mitsubishi Corporation. For the year ended
December 31, 2017
, sales to Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, and Chesapeake accounted for approximately
32%
and
17%
, respectively, of total consolidated revenues. In January 2018, we discontinued the sale of natural gas to Shell in the East Texas and North Louisiana regions as a result of litigation regarding certain natural gas sales contracts. See further discussion in "Part I. Item 3. Legal proceedings" and in "Note 8. Commitments and contingencies". We have not experienced any interruptions or negative impact to our natural gas sales prices as a result the discontinuance of sales to Shell in these regions.
Derivative financial instruments
Our derivative financial instruments are comprised of commodity derivative contracts and the 2017 Warrants (as defined in "Note 4. Derivative financial instruments"). We have historically used commodity derivative financial instruments to mitigate the impacts of commodity price fluctuations, to protect our returns on investments and to achieve a more predictable cash flow. FASB ASC 815,
Derivatives and Hedging,
("ASC 815"), requires that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its estimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 are met. We do not designate our derivative financial instruments as hedging instruments and are not held for trading purposes. Changes in our derivative financial instruments are recorded as non-operating income or expense in our Consolidated Statements of Operations.
Oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development and major development projects, collectively totaled
$155.6 million
and
$118.7 million
as of
December 31, 2018
and
2017
, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the
years ended December 31, 2018 and 2017
.
We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20
, Capitalization of Interest
. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the relationship between capitalized costs and Proved Reserves.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at
10%
, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.
The ceiling test for each period was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.
|
|
|
|
|
|
|
|
|
|
|
|
Average spot prices
|
|
|
Oil (per Bbl)
|
|
Natural gas (per Mmbtu)
|
December 31, 2018
|
|
$
|
65.56
|
|
|
$
|
3.10
|
|
December 31, 2017
|
|
51.34
|
|
|
2.98
|
|
December 31, 2016
|
|
42.75
|
|
|
2.48
|
|
We did not recognize an impairment to our proved oil and natural gas properties for the
years ended December 31, 2018 and 2017
. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.
As of
December 31, 2018
and 2017, all of our undeveloped locations that meet the technical definition of Proved Undeveloped Reserves based on engineering guidelines remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements. Our recognition of proved undeveloped reserves continues to be affected by the uncertainty regarding our availability of capital required to develop these reserves. A significant amount of our proved undeveloped reserves that were previously reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in the future if we determine we have the financial capability to execute a development plan.
The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.
Other property and equipment, net and other non-current assets
Other property and equipment, net and other non-current assets is primarily comprised of surface acreage and buildings and equipment associated with field offices located in our South Texas region. The buildings and equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from
5
to
15
years.
Goodwill
In accordance with FASB ASC 350-20,
Intangibles-Goodwill and Other
("ASC 350-20"), goodwill shall not be amortized, but is tested for impairment at least annually, or more frequently as impairment indicators arise. Impairment tests involve the use of estimates related to the fair market value of the business operations with which goodwill is associated. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations.
As of December 31, 2018, we utilized a discounted cash flow model to value our business and corroborated the results of the valuation model through a comparison to our enterprise value that is calculated as the combined market capitalization of our equity plus the fair value of our debt. The discounted cash flow model used in the income approach requires us to make various judgmental assumptions about future production, revenues, operating and capital expenditures, discount rates and other inputs which are based on our budgets, business plans, economic projections and anticipated future cash flows. Due to the changing market conditions, it is possible that inputs and assumptions used in the valuation may change in the future, which could materially affect the estimate of the fair value of our business. As a result of testing, the fair value of our business significantly exceeded the carrying value of net assets and we did not record an impairment charge for the years ending
December 31, 2018
and
2017
.
Asset retirement obligations
We apply FASB ASC 410-20,
Asset Retirement and Environmental Obligations
("ASC 410-20") to account for estimated future plugging and abandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws.
The following is a reconciliation of our asset retirement obligations for the
years ended December 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Asset retirement obligations at beginning of period
|
|
$
|
12,017
|
|
|
$
|
11,289
|
|
Activity during the period:
|
|
|
|
|
Liabilities incurred during the period
|
|
—
|
|
|
12
|
|
Revisions in estimated assumptions
|
|
(1
|
)
|
|
—
|
|
Liabilities settled during the period
|
|
(77
|
)
|
|
(175
|
)
|
Adjustment to liability due to acquisitions (1)
|
|
2,319
|
|
|
17
|
|
Adjustment to liability due to divestitures
|
|
(7
|
)
|
|
—
|
|
Accretion of discount
|
|
1,054
|
|
|
874
|
|
Asset retirement obligations at end of period
|
|
15,305
|
|
|
12,017
|
|
Less current portion
|
|
600
|
|
|
600
|
|
Long-term portion
|
|
$
|
14,705
|
|
|
$
|
11,417
|
|
|
|
(1)
|
The increase in our asset retirement obligations during the
year ended December 31, 2018
is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement.
|
Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.
Revenue recognition and natural gas imbalances
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The FASB and the International Accounting Standards Board jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method.
We adopted ASU No. 2014-09,
Revenue from Contracts with Customers
and related updates in the first quarter of 2018 based on the modified retrospective method of adoption. The adoption of this standard did not have an impact on our consolidated financial condition and results of operations. We have implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the disclosures required under the new standard.
Overview of marketing arrangements
We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the oil we produce under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are
located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.
We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a month or more. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions.
Revenue recognition under ASC 606
We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Natural gas imbalances at
December 31, 2018
were
0.7
Bcf and were reflected as a reduction to our Proved Reserves. Natural gas imbalances at December 31, 2017 were not significant.
We generally sell oil and natural gas under
two
types of agreements that are common in our industry. Both types of agreements include transportation charges. We evaluate whether we are the principal or the agent in each transaction. The first type of agreement is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation costs incurred by the purchaser. The purchaser takes custody, title and risk of loss of the oil or natural gas at the wellhead. In this case, we record revenue when the control transfers to the purchaser at the wellhead based on the price received, net of the transportation costs.
Under the second type of agreement, we sell oil or natural gas at a specific delivery point, pay transportation to a third-party and receive proceeds from the purchaser with no transportation deduction. The purchaser takes custody, title, and risk of loss of the oil or natural gas at the specific delivery point. In this case, we are deemed to be the principal and the ultimate third-party purchaser is deemed to be the customer. We recognize revenue when control transfers to the purchaser at the specific delivery point based on the price received from the purchaser. The costs that we incur to transport the oil or natural gas are recorded as gathering and transportation expenses. As such, our computed realized prices include revenues that are recognized under two separate bases.
Raider Marketing, LP (“Raider”) is a wholly owned subsidiary focused on the marketing of oil and natural gas. Raider purchases and resells natural gas from third-party producers, as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells. Raider takes custody, title and risk of loss from the third-party producer upon the purchase of natural gas and then sells the natural gas to a separate third-party purchaser further downstream. The price paid for the purchase of natural gas from the third-party producer is not dependent on the price received from the ultimate purchaser. We are deemed to be the principal in these transactions. As such, third party purchases and sales are reported on a gross basis as “Purchased natural gas” expenses and “Purchased natural gas and marketing” revenues, respectively. The marketing fee charged by Raider to certain working interest owners in our operated wells is reported as “Purchased natural gas and marketing” revenues.
Transaction price allocated to remaining performance obligations
Our sales are short-term in nature with a contract term of one year or less. We have utilized the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Contract balances
Under our oil and natural gas sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.
Prior-period performance obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil and natural gas sales may not be received for
30
to
90
days after the date production is delivered, and as a result, we are
required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For
the year ended December 31, 2018
, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Gathering and transportation
As noted earlier in our discussion of revenue recognition, we generally sell oil and natural gas under
two
types of agreements in which both types of agreements include a transportation charge. Under the first agreement, transportation charges are incurred by the purchaser while under the second arrangement, we incur the cost of transportation as receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Gathering and transportation expenses totaled
$76.2 million
and
$111.4 million
for the
years ended December 31, 2018 and 2017
, respectively. Transportation charges for the year ended
December 31, 2018
were lower due to the rejection of certain firm transportation agreements in connection with the bankruptcy proceedings.
Capitalization of internal costs
As part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employees who are directly involved in the acquisition, appraisal, exploration, exploitation and development of oil and natural gas properties. During the
years ended December 31, 2018 and 2017
, we capitalized
$3.3 million
and
$3.9 million
, respectively. The capitalized amounts include
$0.3 million
and
$1.0 million
of share-based compensation for the
years ended December 31, 2018 and 2017
, respectively.
Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners of
$14.1 million
and
$14.6 million
for the
years ended December 31, 2018 and 2017
, respectively, as a reduction of general and administrative expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of
$6.7 million
and
$6.0 million
for the
years ended December 31, 2018 and 2017
, respectively.
In addition, we have agreements with Shell that allow us to bill each other certain personnel costs and related fees incurred on behalf of the joint ventures in the East Texas, North Louisiana and Appalachia regions (prior to the Appalachia JV Settlement). For the
years ended December 31, 2018 and 2017
, general and administrative expenses were reduced by
$4.3 million
and
$6.4 million
, respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by Shell for their personnel and services.
Environmental costs
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes
Income taxes are accounted for in accordance with FASB ASC 740,
Income Taxes
("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings per share
We account for earnings per share in accordance with FASB ASC 260-10,
Earnings Per Share
("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"): basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period and includes warrants representing the right to purchase our common shares at an exercise price of
$0.01
. Basic EPS excludes stock options, restricted share units, restricted
share awards, warrants issued Energy Strategic Advisory Services LLC ("ESAS", the warrants are referred to as "ESAS Warrants") and Financing Warrants (as defined in "Note 4. Derivative financial instruments"). Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards, ESAS Warrants and Financing Warrants, whether exercisable or not.
Equity-based compensation
Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC 718,
Compensation-Stock Compensation
("ASC 718") and equity-based compensation for ESAS Warrants which we accounted for in accordance with FASB ASC 505-50,
Equity-Based Payments to Non-Employees
("ASC 505-50"). See "Note 13. Related party transactions" for further discussion.
ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.
Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards. We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there were no grants of share-based compensation during the
years ended December 31, 2018 and 2017
. See further discussion in "
Note 11. Equity-based and other incentive-based compensation
".
The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment was recorded in our Consolidated Statements of Operations included as equity-based compensation expense. The ESAS Warrants were forfeited and canceled on November 9, 2017 concurrently with the suspension of the services and investment agreement with ESAS. See "
Note 11. Equity-based and other incentive-based compensation
" for additional information of the ESAS Warrants.
Recent accounting pronouncements
In February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02,
Leases
(Topic 842) ("ASU 2016-02"). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted.
In January 2018, the FASB issued further guidance on the new lease standard in ASU No. 2018-01, Leases (Topic 842):
Land Easement Practical Expedient for Transition to Topic 842
(“ASU 2018-01”). ASU 2018-01 provides a practical expedient to exclude existing or expired land easements from the evaluation of leases under ASU 2016-02 if the easements were not previously accounted for as leases under the current guidance. In July 2018, the FASB issued additional guidance on the accounting for leases in ASU No. 2018-10,
Codification Improvements to Topic 842, Leases
, and ASU No. 2018-11, Leases (Topic 842):
Targeted Improvements
(“ASU 2018-11”). ASU 2016-02 was initially required to be adopted using a modified retrospective transition, which would require application of the new guidance at the beginning of the earliest comparative period presented. The guidance in ASU 2018-11 provides companies with another transition method that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings as of the date of adoption. Under this method, previously presented years’ financial positions and results would not be adjusted. The new guidance also provides
lessors with a practical expedient, by class of underlying asset, to not separate non-lease components from the associated lease component if (1) the non-lease components would otherwise be accounted for under the new revenue recognition standard, (2) both the timing and pattern of transfer are the same for the non-lease components and associated lease component, and (3) if accounted for separately, the lease component would be classified as an operating lease.
We are substantially complete with the adoption of the ASUs related to the new lease standard using the optional transition method on January 1, 2019, which will not require an adjustment to the opening balance of shareholders' equity. We plan to adopt the practical expedient package, the land easement and short-term lease recognition exemption provided for under the new standard. Also, we plan to elect a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease. We anticipate that we will recognize a right-of-use asset and corresponding lease liability of approximately
$4 million
to
$6 million
upon adoption in our Consolidated Balance Sheet.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230):
Restricted Cash (a consensus of the FASB Emerging Issues Task Force)
(“ASU 2016-18”). The amendments in this update require that a statement of cash flows explain the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We adopted ASU 2016-18 in the first quarter of 2018 utilizing retrospective application. The adoption resulted in an increase in reported investing cash flows of
$4.1 million
for the
year ended December 31, 2017
with a corresponding adjustment to the reported end of period cash balances.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805):
Clarifying the Definition of a Business
(“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If this threshold is not met, the entity then evaluates whether the set meets the requirement that a business includes, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. We adopted ASU 2017-01 in the first quarter of 2018 and will apply the guidance of ASU 2017-01 prospectively to future asset acquisitions, including the acquisitions as part of the Appalachia JV Settlement during the first quarter of 2018.
In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815):
I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception
(“ASU 2017-11”). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40,
Derivatives and Hedging - Contracts in Entity’s Own Equity
, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. An entity is still required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants (as defined in “Note 4. Derivative financial instruments”) are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it could have an impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. However, we believe it is highly likely that our existing common shares as well as the 2017 Warrants will be canceled at the conclusion of our Chapter 11 Cases.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740):
Amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118
(“ASU 2018-05”). The amendments in this update add various SEC paragraphs pursuant to the issuance of SEC Staff Accounting Bulletin No. 118,
Income Tax Accounting Implications of the Tax Cuts and Jobs Act
(“SAB 118”). SAB 118 directs taxpayers to consider the implications of the Tax Cuts and Jobs Act (“Tax Act”) as provisional when it does not have the necessary information available, prepared, or analyzed in reasonable detail to complete its accounting for the change in the tax law. SAB 118 provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. We reflected the impact of the changes in rates on our deferred tax assets and liabilities at December 31, 2017, as we are required to reflect the change in the period in which the law is enacted. We completed our analysis of the impact of the Tax Act during 2018 and the impact of any changes are reflected in
our deferred tax assets and liabilities at December 31, 2018. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.
In June 2018, the FASB issued ASU No. 2018-07, Compensation—Stock Compensation (Topic 718):
Improvements to Nonemployee Share-Based Payment Accounting
(“ASU 2018-07”). The amendments in this update expand the scope of Topic 718 to include share-based payment transactions for acquiring goods or services from nonemployees. An entity should apply the requirements of Topic 718 to nonemployee awards except in certain circumstances. ASU 2018-07 clarifies that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be consumed in a grantor’s operations unless the transaction effectively provides financing to the grantor or are awarded under a contract accounted for under Topic 606 (as defined below). ASU 2018-07 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2018. The amendments require that adjustments required upon application of the update be made through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. We have historically awarded share-based compensation to nonemployees; however, we do not currently have any outstanding share-based awards to nonemployees. Therefore, we do not believe the adoption of ASU 2018-07 will have an impact on our consolidated financial condition and results of operations unless share-based payments are issued to nonemployees in the future.
In July 2018, the FASB issued ASU No. 2018-09, Codification Improvements (“ASU 2018-09”). The amendments in this update include changes to clarify and make other incremental improvements to GAAP under the FASB’s perpetual project to address suggestions from stakeholders. The amendments in this update affect a wide variety of topics and apply to all reporting entities within the scope of the affected accounting guidance. The transition and effective date guidance is based on the facts and circumstances of each amendment. A number of the amendments do not require transition guidance and are effective as of the issuance of the update while many of the updates that have transition guidance are effective for annual periods beginning after December 15, 2018. For amendments relating to issued but not effective guidance, the effective date of these amendments follows that of the originally issued update. We are currently assessing the potential impact of the many amendments within ASU 2018-09 and are currently unable to quantify the impact, if any, the standard will have on our consolidated financial condition and results of operations.
3.
Acquisitions, divestitures and other significant events
2018 Acquisitions
Appalachia JV Settlement
On January 26, 2018, we filed a motion in the Court to authorize the entry into a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region. The final order related to this settlement was approved on February 22, 2018 and we closed the settlement agreement on
February 27, 2018
("Appalachia JV Settlement"). Under the terms of the Appalachia JV Settlement:
|
|
•
|
Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and Appalachia Midstream, LLC (“Appalachia Midstream”). On April 20, 2018, BG Production Company (PA), LLC legally changed its name to EXCO Production Company (PA) II, LLC and BG Production Company (WV), LLC legally changed its name to EXCO Production Company (WV) II, LLC;
|
|
|
•
|
Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV;
|
|
|
•
|
EXCO reconveyed its interests in certain leases, representing an interest in
364
net acres, that EXCO had previously acquired from Shell within the area of mutual interest, in exchange for consideration of
$0.7 million
;
|
|
|
•
|
EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages and remedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest, the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region, except as expressly provided in the settlement; and
|
|
|
•
|
EXCO caused the arbitration and the state court action to be dismissed with prejudice.
|
The settlement increased our acreage in the Appalachia region by approximately
177,700
net acres, and the production from the additional interests in producing wells acquired was
26
net Mmcfe per day during December 2017. In addition, EXCO now owns
100%
of OPCO and Appalachia Midstream subsequent to the settlement. Prior to the settlement, we accounted for our
50%
ownership interests in OPCO and Appalachia Midstream as equity method investments. The entities associated with
the Appalachia JV Settlement, including EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC, OPCO, and Appalachia Midstream, have not filed for relief under Chapter 11 of the Bankruptcy Code, and the operations of these entities are not expected to be affected by the Chapter 11 Cases.
We accounted for the acquisitions in accordance with FASB ASC 805,
Business Combinations
. The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Appalachia JV Settlement as of the closing date.
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Assets acquired:
|
|
|
Cash and cash equivalents
|
|
$
|
14,832
|
|
Accounts receivable, net
|
|
6,493
|
|
Other current assets
|
|
5,264
|
|
Unproved oil and natural gas properties
|
|
33,542
|
|
Proved developed and undeveloped oil and natural gas properties, net
|
|
72,548
|
|
Other assets
|
|
18,109
|
|
Liabilities assumed:
|
|
|
Accounts payable and accrued liabilities
|
|
(9,718
|
)
|
Asset retirement obligations
|
|
(2,315
|
)
|
Other long-term liabilities
|
|
(9,895
|
)
|
Fair value of net assets acquired
|
|
$
|
128,860
|
|
The fair value of the assets and liabilities acquired as part of the Appalachia JV Settlement of
$128.9 million
resulted in a gain of
$119.2 million
after remeasurement of our previously held equity interest in OPCO and Appalachia Midstream and adjustments to certain balances held by OPCO. As of the closing date, the carrying value of our equity investments in OPCO and Appalachia Midstream was
$9.6 million
.
We performed a valuation of the assets and liabilities acquired as of the closing date. A summary of the key inputs is as follows:
Working capital
- The fair value approximated the carrying value for working capital including cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities.
Oil and natural gas properties
- The fair value allocated to unproved and proved oil and natural gas properties was
$33.5 million
and
$72.5 million
, respectively. The fair value of oil and natural gas properties was determined based on a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering and financial data. We utilized NYMEX forward strip prices to value the reserves then applied various discount rates depending on the classification of reserves and other risk characteristics.
Other assets -
The fair value allocated to other assets was
$18.1 million
, which is primarily comprised of natural gas gathering assets held by Appalachia Midstream. The fair value of the natural gas gathering assets was determined based on transaction multiples of peer companies and a discounted cash flow model from our internally generated oil and natural gas reserves for the related properties.
Asset retirement liabilities
- The fair value allocated to asset retirement obligations was
$2.3 million
. These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate proved producing properties at the end of their productive lives, in accordance with applicable state laws. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs.
Firm transportation contract
- OPCO holds a contract that requires it to transport a minimum volume of natural gas or pay reservation charges. The performance obligations under the contract exceeded the future economic benefit to be received over the life of the contract. We calculated the fair value as the present value of the remaining unused commitments discounted at a rate consistent with market participants. The fair value of the liability was
$12.1 million
, including the current portion of
$2.2 million
and the long-term portion of
$9.9 million
.
Pro forma results of operations
- The following table reflects the unaudited pro forma results of operations if the Appalachia JV Settlement had occurred on January 1, 2017:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands except for per share data)
|
2018
|
|
2017
|
Oil and natural gas revenues
|
$
|
398,105
|
|
|
$
|
305,371
|
|
Net income (loss) (1)
|
(181,437
|
)
|
|
27,971
|
|
Basic earnings (loss) per share
|
$
|
(8.37
|
)
|
|
$
|
1.31
|
|
Diluted earnings (loss) per share
|
$
|
(8.37
|
)
|
|
$
|
1.31
|
|
|
|
(1)
|
The pro forma results of operations include adjustments for revenues and direct expenses related to the interests acquired as part of the Appalachia JV Settlement. Net income (loss) for the
year ended December 31, 2018
includes the non-cash gains or losses associated with the fair value of net assets acquired and remeasurement of previously held interests in OPCO and Appalachia Midstream.
|
Related party transactions
- As noted previously, prior to the Appalachia JV Settlement, we accounted for our
50%
ownership interests in OPCO and Appalachia Midstream as equity method investments. OPCO served as the operator of our wells in the Appalachia JV and we advanced funds to OPCO on an as needed basis. Additionally, there are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. Prior to the closing of the settlement, we received
$1.7 million
under these agreements during 2018. We received
$6.6 million
under these agreements during 2017. As of December 31, 2017, we recorded a receivable of
$0.6 million
for services performed on behalf of OPCO in "Accounts receivable, net — Other" and a payable of
$3.7 million
for advances owed to OPCO in "Accounts payable and accrued liabilities" on our Consolidated Balance Sheet. During the year ended December 31, 2017, we received a
$6.0 million
cash distribution from Appalachia Midstream.
2017 Acquisitions and termination of South Texas divestiture
Termination of South Texas divestiture
On April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil and natural gas properties and surface acreage in South Texas for a total purchase price of
$300.0 million
that was subject to closing conditions and adjustments based on an effective date of January 1, 2017.
Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original Scheduled Closing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreement included conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as of the Original Scheduled Closing Date. On May 31, 2017, Chesapeake Energy Marketing, L.L.C. (“CEML”) purportedly terminated a long-term natural gas sales contract with an expiration of June 30, 2032, between CEML and Raider Marketing, LP (“Raider”), a wholly owned subsidiary of EXCO.
On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against CEML and subsequently added the parent entity, Chesapeake Energy Corporation ("CEC"). In the lawsuit, we assert breach of contract, tortious interference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, CEML filed to remove the lawsuit to the United States District Court Northern District of Texas. On June 9, 2017, the District Court denied our motion for temporary restraining order. CEC filed a motion to dismiss on the basis of personal jurisdiction, and the motion remains pending.
Due to the purported contract termination, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date. Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017. The amendment, among other things, provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of the natural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017, EXCO and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no further effect.
North Louisiana acquisitions
During the year ended December 31, 2017, we closed acquisitions of certain oil and natural gas properties and undeveloped acreage in the North Louisiana region for
$24.2 million
. The total purchase price was primarily allocated to
$5.2 million
of unproved oil and natural gas properties and
$19.0 million
of proved oil and natural gas properties.
4.
Derivative financial instruments
Our derivative financial instruments are comprised of commodity derivatives and common share warrants.
The table below presents the effect of derivative financial instruments on our Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
Current assets
|
|
Derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
1,150
|
|
Liabilities subject to compromise
|
|
Derivative financial instruments - common share warrants
|
|
(61
|
)
|
|
—
|
|
Long-term liabilities
|
|
Derivative financial instruments - common share warrants
|
|
—
|
|
|
(1,950
|
)
|
The table below presents the effect of derivative financial instruments on our Consolidated Statements of Operations.
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Gain (loss) on derivative financial instruments - commodity derivatives
|
|
$
|
(615
|
)
|
|
$
|
24,732
|
|
Gain on derivative financial instruments - common share warrants
|
|
1,889
|
|
|
159,190
|
|
Commodity derivative financial instruments
We have historically entered into commodity derivative financial instruments with the primary objective to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our commodity derivative financial instruments consists of non-cash income or expense due to changes in the fair value. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our commodity derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.
Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Consolidated Balance Sheets fair value amounts.
Our oil and natural gas derivative instruments during the
year ended December 31, 2017
were comprised of swap contracts, which allowed us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. At
December 31, 2017
, we had outstanding swap contracts covering
3,650
Bbtu of natural gas at a weighted average strike price of
$3.15
per Mmbtu. In January 2018, the counterparty to our remaining open swap contracts early terminated the outstanding contracts effective January 31, 2018. We received proceeds of
$0.5 million
for the settlement of these contracts in February 2018. As of
December 31, 2018
, we did not have any outstanding commodity derivative financial instruments.
The DIP Credit Agreement permits us to enter into commodity derivative contracts up to
90%
of the reasonably anticipated projected production from our proved developed producing reserves for any month during the forthcoming five year period. We are only permitted to enter into additional commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, this limits our options to enter into commodity derivative contracts covering our production in future periods. Our exposure to commodity price fluctuations will increase in the future due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels.
Common share warrants
In connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of the 1.5 Lien Notes representing the right to purchase an aggregate of up to
21,505,383
common shares (assuming a cash exercise) at an exercise price of
$13.95
per share (“Financing Warrants”), and warrants representing the right to purchase an aggregate of up to
431,433
common shares (assuming a cash exercise) at an exercise price of
$0.01
per share (“Commitment Fee Warrants”). In addition, certain exchanging holders of the Second Lien Term Loans received warrants representing the right to purchase an aggregate of up to
1,325,546
common shares (assuming a cash exercise) at an exercise price of
$0.01
per share (“Amendment Fee Warrants”, and with the Commitment Fee Warrants and Financing Warrants, collectively referred to as the “2017 Warrants”).
Pursuant to the terms of the 2017 Warrants, the 2017 Warrants may not be exercised, subject to certain exceptions and limitations, if, as a result of such exercise, the holder or its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exercise term of five years from May 31, 2017 and, subject to certain exceptions, may be exercised by cash or cashless exercise. The Financing Warrants are subject to an anti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the Financing Warrants, subject to certain adjustments and exceptions. The Commitment Fee Warrants and the Amendment Fee Warrants are subject to an anti-dilution adjustment in the event we issue common shares at a price per share less than
$10.50
per share, subject to certain exceptions and adjustments. The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815,
Derivatives and Hedging
, (“ASC 815”), and are required to be classified as liabilities due to the types of anti-dilution adjustments.
We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. On January 16, 2018, affiliates of Fairfax, which had previously been identified as a related party, surrendered all of their rights to 2017 Warrants. Their rights under the 2017 Warrants had entitled them to purchase in aggregate up to
10,824,376
common shares at
$13.95
per share and
1,725,576
common shares at
$0.01
per share. The remaining 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise or the date of expiration. As a result of the change in the fair value of the 2017 Warrants, we recorded gains of
$1.9 million
and
$159.2 million
during the
years ended December 31, 2018 and 2017
, respectively, on the revaluation of the warrants, in “
Gain on derivative financial instruments - common share warrants
” on the Consolidated Statements of Operations. The gains were primarily due to a decrease in our share price and the cancellation of warrants by affiliates of Fairfax.
5.
Debt
The carrying value of our total debt is summarized as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2018
|
|
December 31, 2017
|
DIP Credit Agreement
|
|
$
|
156,406
|
|
|
$
|
—
|
|
EXCO Resources Credit Agreement
|
|
—
|
|
|
126,401
|
|
1.5 Lien Notes, net of unamortized discount
|
|
316,958
|
|
|
176,560
|
|
1.75 Lien Term Loans, net of unamortized discount
|
|
708,926
|
|
|
845,763
|
|
Second Lien Term Loans
|
|
17,246
|
|
|
23,543
|
|
2018 Notes, net of unamortized discount
|
|
131,576
|
|
|
131,345
|
|
2022 Notes
|
|
70,169
|
|
|
70,169
|
|
Deferred financing costs, net
|
|
—
|
|
|
(11,281
|
)
|
Total debt, net
|
|
1,401,281
|
|
|
1,362,500
|
|
Less amounts included in liabilities subject to compromise
|
|
927,917
|
|
|
—
|
|
Current maturities of long-term debt
|
|
$
|
473,364
|
|
|
$
|
1,362,500
|
|
As of December 31, 2017, we classified all of our outstanding indebtedness as a current liability as a result of agreements entered into in anticipation of events of default under certain debt agreements, as well as any outstanding debt with cross-default provisions, and an event of default under the Second Lien Term Loans. The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes and 2022 Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments were automatically stayed as a result of the
commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.
As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. This resulted in expenses of
$24.4 million
for the acceleration of (i) deferred financing costs, (ii) debt discounts, and (iii) deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, which was classified as “Reorganization items, net” in our Consolidated Statement of Operations for the
year ended December 31, 2018
. As discussed below, the proceeds from the DIP Facilities were used to repay all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated. The financing costs of
$6.1 million
that were directly attributable to the DIP Credit Agreement were expensed as “Reorganization items, net” in our Consolidated Statement of Operations for the
year ended December 31, 2018
. As of December 31, 2018, the carrying value for each of our debt instruments approximates the principal amount.
On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. For the
year ended December 31, 2018
, we made cash interest payments on the DIP Credit Agreement and the 1.5 Lien Notes of
$9.6 million
and
$25.4 million
, respectively. The principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes as of December 31, 2018, were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimate of the recoverability of claims related to these debt instruments. We accrued interest on 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through the Petition Date with no interest accrued subsequent to the filings. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes are classified as “Liabilities subject to compromise” on the Consolidated Balance Sheet as of December 31, 2018. The accrued interest related to these instruments classified as "Liabilities subject to compromise" is presented in the following table.
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2018
|
1.75 Lien Term Loans
|
|
$
|
28,800
|
|
Second Lien Term Loans
|
|
701
|
|
2018 Notes
|
|
3,289
|
|
2022 Notes
|
|
1,491
|
|
Accrued interest payable classified as Liabilities subject to compromise
|
|
$
|
34,281
|
|
DIP Credit Agreement
On January 18, 2018, the Court entered into an interim order that authorized us to enter into the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement, which includes the Revolver A Facility in an aggregate principal amount of
$125.0 million
and the Revolver B Facility in an aggregate principal amount of
$125.0 million
(collectively with the Revolver A Facility, the "DIP Facilities") with the DIP Lenders. Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The proceeds of the DIP Facilities were to be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCO Resources Credit Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a budget provided to the DIP Lenders under the DIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses, and (iv) pay for certain other costs and expenses of administering the Chapter 11 Cases. We used approximately
$104.0 million
of the proceeds provided through the DIP Facilities to repay all obligations outstanding under the EXCO Resources Credit Agreement. Under the DIP Credit Agreement, approximately
$24.0 million
of outstanding letters of credit were deemed issued under the Revolver A Facility, and approximately
$21.6 million
of loans outstanding under the EXCO Resources Agreement were deemed exchanged for loans under the Revolver B Facility.
On February 22, 2018, the Court entered into a final order authorizing entry into the DIP Credit Agreement on a final basis. The entry into the final order resulted in the termination of the EXCO Resources Credit Agreement.
As of December 31, 2018
, we had
$156.4 million
in outstanding indebtedness and
$12.0 million
of letters of credit outstanding under the DIP Facilities. Our available borrowing capacity under the DIP Facilities was
$81.6 million
as of
December 31, 2018
.
All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus
4.00%
per annum. During the continuance of an event of default under the DIP Facilities, the outstanding amounts bear interest at an additional
2.00%
per annum above the interest rate otherwise applicable. The rate applicable to borrowings under the DIP Facilities at
December 31, 2018
was
6.53%
per annum.
The DIP Facilities were set to mature on the earliest of (a) January 22, 2019, (b) the effective date of a plan of reorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. On January 15, 2019, the Company entered into an amendment to the DIP Credit Agreement (the “DIP Amendment”) that extended the maturity date. The DIP Credit Agreement, as amended by the DIP Amendment, will mature on the earliest of (i) May 22, 2019, (ii) the effective date of a plan of reorganization in the Chapter 11 Cases, and (iii) the date of termination following an event of default of all revolving commitments and/or the acceleration of the obligations under the our senior secured debtor-in possession revolving credit facilities. In accordance with its terms, the DIP Amendment became effective on January 18, 2019. We have not received consents from any creditors in support of the March 2019 Plan; therefore, our ability to confirm a plan of reorganization in a timely manner is highly uncertain due to factors beyond our control, including actions of the Court and creditors. As a result, it is unlikely that we will be able to consummate a plan of reorganization prior to the maturity of the DIP Facilities. Therefore, our long-term liquidity is highly dependent on our ability to obtain consents or waivers to further extend the DIP Facilities beyond the scheduled maturity date of May 22, 2019 or refinance the DIP Facilities if we are unable to obtain to consummate a plan of reorganization in a timely manner.
Borrowings under the DIP Credit Agreement remain subject to an initial borrowing base of
$250.0 million
. A redetermination of the borrowing base is scheduled to occur on April 1, 2019 based upon the value of our oil and gas reserves. The DIP Lenders have considerable discretion in setting our borrowing base as part of the redetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of the net present value, discounted at
nine
percent, of our proved developed reserves.
The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below), at all times: (i) are entitled to joint and several super-priority administrative expense claim status in the Chapter 11 Cases; (ii) have a first priority lien on substantially all of our assets; (iii) have a junior lien on any of our assets subject to a valid, perfected and non-avoidable lien as of the Petition Date, other than such liens securing the obligations under the 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of
100%
of the stock and other equity interests in each of our direct and indirect subsidiaries. Our obligations to the DIP Lenders and the liens and super-priority claims are subject in each case to a carve out ("Carve-Out") that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.
The DIP Credit Agreement contains certain financial covenants, including, but not limited to:
|
|
•
|
our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than
$20.0 million
; and
|
|
|
•
|
aggregate disbursements cannot exceed
120%
of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the DIP Agent. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the DIP Agent.
|
As of December 31, 2018,
we were in compliance with all of the covenants under the DIP Credit Agreement
. The DIP Credit Agreement contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Facilities contained an event of default if we failed to pursue a Court hearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets; however, the final order entered by the Court deemed this requirement to be no longer in force and effect.
EXCO Resources Credit Agreement
As of December 31, 2017, we borrowed substantially all of our remaining unused commitments and had
$126.4 million
of outstanding indebtedness and
$23.0 million
of outstanding letters of credit under the EXCO Resources Credit Agreement as of December 31, 2017. The borrowing base under the EXCO Resources Credit agreement was
$150.0 million
as of December 31, 2017. As a result, the availability remaining under the EXCO Resources Credit Agreement, including letters of credit, was
$0.6 million
as of December 31, 2017. Borrowings under the EXCO Resources Credit Agreement were collateralized by first lien mortgages providing a security interest of not less than
80%
of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base.
On December 19, 2017, we entered into a forbearance agreement with the lenders under the EXCO Resources Credit Agreement. Pursuant to this agreement, the lenders under the EXCO Resources Credit Agreement agreed to forbear from
exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement.
1.5 Lien Notes
On March 15, 2017, we issued an aggregate of
$300.0 million
of 1.5 Lien Notes due March 20, 2022 to affiliates of Fairfax Financial Holdings Limited ("Fairfax"), Bluescape Resources Company LLC ("Bluescape"), Oaktree Capital Management, LP ("Oaktree"), and an unaffiliated investor. We used the majority of the proceeds from the issuance of the 1.5 Lien Notes to repay the entire amount outstanding under the EXCO Resources Credit Agreement in March 2017. As described in “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.5 Lien Notes, we also issued the Commitment Fee Warrants and the Financing Warrants with a combined fair value of
$148.6 million
. The combined fair value of the warrants and
$4.5 million
of cash paid to certain investors who elected to receive cash in lieu of Commitment Fee Warrants was recorded as a discount to the 1.5 Lien Notes. The discount and
$4.3 million
of transaction costs incurred related to the transaction were being amortized to interest expense over the life of the 1.5 Lien Notes until the acceleration of the costs at the Petition Date.
The 1.5 Lien Notes bear interest at a cash interest rate of
8%
per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certain circumstances, by issuing additional 1.5 Lien Notes, at an interest rate of
11%
per annum. Interest is payable bi-annually on March 20 and September 20 of each year, commencing on September 20, 2017. On September 20, 2017, we paid the interest due on the 1.5 Lien Notes in-kind with approximately
$17.0 million
of aggregate principal amount of 1.5 Lien Notes, resulting in
$317.0 million
of total aggregate principal amount of 1.5 Lien Notes outstanding. On December 19, 2017, we entered into a forbearance agreement with certain lenders under the 1.5 Lien Notes. Pursuant to this agreement, the lenders under the 1.5 Lien Notes agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement.
1.75 Lien Term Loans and Second Lien Term Loan Exchange
During 2015, we closed a
12.5%
senior secured second lien term loan with certain affiliates of Fairfax in the aggregate principal amount of
$300.0 million
("Fairfax Term Loan") and a
12.5%
senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of
$400.0 million
(“Exchange Term Loan" and together with the Fairfax Term Loan, "Second Lien Term Loans"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60,
Troubled Debt Restructuring by Debtors
.
In connection with the offering of the 1.5 Lien Notes, on March 15, 2017, we completed the Second Lien Term Loan Exchange whereby approximately
$682.8 million
in aggregate principal amount of the outstanding Second Lien Term Loans, consisting of all of the outstanding indebtedness under the Fairfax Term Loan and approximately
$382.8 million
in aggregate principal amount of the Exchange Term Loan, were exchanged for approximately
$682.8 million
in aggregate principal amount of 1.75 Lien Term Loans. As described in “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.75 Lien Term Loans, we also issued the Amendment Fee Warrants with a fair value of
$12.6 million
. The fair value of the Amendment Fee Warrants issued to the lenders of the 1.75 Lien Term Loans and the
$8.6 million
of cash paid to the lenders who elected to receive cash in lieu of warrants was recorded as a discount to the 1.75 Lien Term Loans, and was being amortized to interest expense over the life of the loans until the acceleration of the discount at the Petition Date.
As a result of the Second Lien Term Loan Exchange, the Fairfax Term Loan was deemed satisfied and paid in full and was terminated. In addition, by participating in the Second Lien Term Loan Exchange, each exchanging lender was deemed to have consented to an amendment to the Second Lien Term Loans that eliminated substantially all of the restrictive covenants and events of default in the agreements governing the Second Lien Term Loans. Following the Second Lien Term Loan Exchange, we had approximately
$17.2 million
in aggregate principal amount of Second Lien Term Loans outstanding, consisting entirely of the remaining portion of the Exchange Term Loan. The Second Lien Term Loan Exchange was accounted for as a modification of debt, and no gain or loss was recognized on the exchange. The transaction costs related to the Second Lien Term Loan Exchange of
$6.4 million
were recorded in "Loss on restructuring and extinguishment of debt" in our Consolidated Statement of Operations for the year ended December 31, 2017.
The 1.75 Lien Term Loans are due on October 26, 2020, bear interest at a cash rate of
12.5%
per annum, or, if we elect to pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75
Lien Term Loans, at an interest rate of
15.0%
per annum. On September 20, 2017, we paid the interest due on the 1.75 Lien Term Loans in-kind with approximately
$26.2 million
of aggregate principal amount of 1.75 Lien Term Loans, resulting in
$708.9 million
of total aggregate principal amount of 1.75 Lien Term Loans outstanding. On December 19, 2017, we entered into a forbearance agreement with certain lenders under the 1.75 Lien Term Loans. Pursuant to this agreement, the lenders under the 1.75 Lien Term Loans agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement.
PIK Payments under the 1.5 Lien Notes and the 1.75 Lien Term Loans
The principal purpose of issuing the 1.5 Lien Notes and Second Lien Term Loan Exchange was to alleviate our substantial cash interest payment burden and improve our Liquidity. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans were intended to allow us to make payments in additional indebtedness or common shares ("PIK Payments"), subject to certain restrictions and limitations.
On June 20, 2017, we issued a total of
2,745,754
common shares ("PIK Shares") in lieu of an approximate
$23.0 million
cash interest payment under the 1.75 Lien Term Loans. The number of PIK Shares issued was calculated based on the interest rate for PIK Payments of
15.0%
, which resulted in a value of
$27.6 million
for the interest payment. The price of the Company's common shares for determining PIK Shares was based on the trailing 20-day volume weighted average price calculated as of the end of the three trading days prior to February 28, 2017.
Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75 Lien Term Loans throughout the remainder of 2017 and 2018. However, there were significant limitations on our ability to make PIK Payments as a result of restrictions in the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans.
Covenants, events of default and other material provisions under the 1.5 Lien Notes and the 1.75 Lien Term Loans
The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans contain covenants limit our ability and the ability of our restricted subsidiaries to, among other things, incur additional indebtedness, transfer assets or make certain types of payments. The 1.5 Lien Notes and 1.75 Lien Term Loans contain customary events of default, including the filing of a petition for relief under the Bankruptcy Code, which require the payment of each of the 1.5 Lien Notes and the 1.75 Lien Term Loans in an amount equal to the outstanding principal amount plus an applicable make-whole premium. The enforceability of the make-whole premium on the 1.5 Lien Notes and 1.75 Lien Term Loans is subject to the outcome of the Chapter 11 Cases.
The 1.5 Lien Notes, 1.75 Lien Term Loans and the Second Lien Term Loans are jointly and severally guaranteed by all of the our restricted subsidiaries and are secured by first priority liens on substantially all of our assets and such guarantors. In connection with the offering of the 1.5 Lien Notes and the Second Lien Term Loan Exchange, we entered into an amended and restated intercreditor agreement, under which the lenders of the remaining outstanding portion of the Exchange Term Loan agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes and the 1.75 Lien Term Loans. In addition, the lenders of the 1.75 Lien Term Loans agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes. The 1.5 Lien Notes, 1.75 Lien Term Loans and the Second Lien Term Loans are effectively senior to all our existing and future unsecured indebtedness, including the 2018 Notes and 2022 Notes, in each case to the extent of the collateral.
2018 and 2022 Notes
The 2018 Notes and 2022 Notes are guaranteed on a senior unsecured basis by substantially all of EXCO’s subsidiaries. Our equity investments, other than those acquired as part of the Appalachia JV Settlement, have been designated as unrestricted subsidiaries under the indentures governing the 2018 Notes and 2022 Notes. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022 Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes. As of December 31, 2018,
$131.6 million
and
$70.2 million
in principal were outstanding on the 2018 Notes and 2022 Notes, respectively. Interest accrued on the 2018 Notes at
7.5%
per annum and was payable semi-annually in arrears on March 15 and September 15 of each year. Interest accrued on the 2022 Notes at
8.5%
per annum and was payable semi-annually in arrears on April 15 and October 15 of each year. The maturity date of the 2018 Notes was September 15, 2018 and the maturity date of the 2022 Notes is April 15, 2022. The repayment of the interest and principal obligations was stayed as part of the Chapter 11 proceedings and recorded as "Liabilities subject to compromise" on the Consolidated Balance Sheet as of the December 31, 2018.
6.
Fair value measurements
We value our derivatives and other financial instruments according to FASB ASC 820,
Fair Value Measurements and Disclosures
, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (“exit price”) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
We categorize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:
Level 1 –
Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.
Level 2 –
Observable inputs other than quoted prices within
Level 1
for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.
Level 3 –
Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.
During the
years ended December 31, 2018 and 2017
there were no changes in the fair value level classifications.
Fair value of derivative financial instruments
The following table presents a summary of the estimated fair value of our derivative financial instruments as of
December 31, 2018
and
2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Liabilities:
|
|
|
|
|
|
|
|
|
Derivative financial instruments - common share warrants
|
|
$
|
—
|
|
|
$
|
61
|
|
|
$
|
—
|
|
|
$
|
61
|
|
|
|
As of December 31, 2017
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
Derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
1,150
|
|
|
$
|
—
|
|
|
$
|
1,150
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Derivative financial instruments - common share warrants
|
|
—
|
|
|
1,950
|
|
|
—
|
|
|
1,950
|
|
Derivative financial instruments - commodity derivatives
We have historically evaluated commodity derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Consolidated Balance Sheets. Net commodity derivative asset values are determined primarily by quoted NYMEX futures prices, notional volumes and utilization of the counterparties’ credit-adjusted risk-free rate curves and net commodity derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period. The fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers or sellers.
Derivative financial instruments - common share warrants
The liability attributable to our common share warrants as of the issuance date and the end of each reporting period is measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration.
See further details on our derivative financial instruments in “
Note 4. Derivative financial instruments
”.
Fair value of other financial instruments
Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature.
The carrying values of our borrowings under the DIP Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods.
The estimated fair values of our senior notes and term loans are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair values of the 1.5 Lien Notes and Second Lien Term Loans were calculated based on a model internally prepared by management that lacks significant observable inputs and was classified as Level 3. The 1.75 Lien Term Loans has been calculated based on quoted prices obtained from third-party pricing sources that lack significant observable inputs and are classified as Level 3. The 2017 Warrants are considered freestanding financial instruments and are not considered in the determination of the fair value of the 1.5 Lien Notes and 1.75 Lien Term Loans. See “
Note 5. Debt
” for the carrying value and the principal balance of each debt instrument included in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
1.5 Lien Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
272,609
|
|
|
$
|
272,609
|
|
1.75 Lien Term Loans
|
|
—
|
|
|
—
|
|
|
216,222
|
|
|
216,222
|
|
Second Lien Term Loans
|
|
—
|
|
|
—
|
|
|
4,185
|
|
|
4,185
|
|
2018 Notes
|
|
23,330
|
|
|
—
|
|
|
—
|
|
|
23,330
|
|
2022 Notes
|
|
12,653
|
|
|
—
|
|
|
—
|
|
|
12,653
|
|
|
|
As of December 31, 2017
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
1.5 Lien Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
232,276
|
|
|
$
|
232,276
|
|
1.75 Lien Term Loans
|
|
—
|
|
|
—
|
|
|
372,186
|
|
|
372,186
|
|
Second Lien Term Loans
|
|
—
|
|
|
—
|
|
|
9,054
|
|
|
9,054
|
|
2018 Notes
|
|
4,658
|
|
|
—
|
|
|
—
|
|
|
4,658
|
|
2022 Notes
|
|
2,586
|
|
|
—
|
|
|
—
|
|
|
2,586
|
|
|
|
7.
|
Environmental regulation
|
Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.
|
|
8.
|
Commitments and contingencies
|
The following table presents our future minimum obligations under our commercial commitments as of
December 31, 2018
. The commitments do not include those of our equity method investments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Drilling contracts
|
|
Operating leases and other
|
|
Other fixed commitments
|
|
Total
|
2019
|
|
$
|
3,661
|
|
|
$
|
1,635
|
|
|
$
|
17
|
|
|
$
|
5,313
|
|
2020
|
|
—
|
|
|
1,595
|
|
|
12
|
|
|
1,607
|
|
2021
|
|
—
|
|
|
1,193
|
|
|
2
|
|
|
1,195
|
|
2022
|
|
—
|
|
|
1,173
|
|
|
—
|
|
|
1,173
|
|
2023
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Thereafter
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
3,661
|
|
|
$
|
5,596
|
|
|
$
|
31
|
|
|
$
|
9,288
|
|
We lease our offices and certain equipment. Our rental expenses were approximately
$2.4 million
and
$2.3 million
for the
years ended December 31, 2018 and 2017
, respectively. We have also entered into drilling rig contracts primarily to develop our assets in the East Texas and North Louisiana regions. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties. These contracts are short-term in nature and are dependent on our planned drilling program.
In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil and natural gas sold. We have reserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations.
We believe that we have properly reflected any potential exposure in our financial position when determined to be both probable and estimable.
Shell natural gas sales contract litigation
As of September 30, 2018, we had withheld
$28.5 million
in revenues owed to Shell as a result of a dispute regarding the failure of Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, to pay us for the sale of natural gas. We entered into a settlement agreement with Shell on September 17, 2018 that was approved by the Court on October 1, 2018 ("Shell Settlement Agreement"). Under the terms of the settlement agreement:
|
|
•
|
EXCO will pay a total of
$22.5 million
to Shell, including
$9.0 million
within 15 days following the approval of the settlement agreement by the Court,
$9.0 million
within 45 days following the approval of the Court, and the remaining
$4.5 million
on or before the effective date of the plan of reorganization. Per the terms of the Shell Settlement Agreement, we paid Shell $18.0 million during the fourth quarter of 2018. Upon payment in full of the remaining amount, Shell shall release EXCO from any further liability related to the withheld revenues;
|
|
|
•
|
EXCO will commence the completion of four wells that were previously drilled in North Louisiana no later than November 15, 2018, and subsequently commence the completion of three additional wells that were previously drilled in North Louisiana. Per the terms of the Shell Settlement Agreement, we commenced completion on each of these wells during the fourth quarter of 2018 and first quarter of 2019;
|
|
|
•
|
EXCO shall assume the joint development agreement with Shell for the East Texas/ North Louisiana joint venture as part of the bankruptcy proceedings and any defaults occurring thereunder are deemed to be satisfied; and
|
|
|
•
|
Shell shall not challenge EXCO’s right to serve as operator under the joint development agreement for the East Texas/ North Louisiana joint venture for the remaining term through January 1, 2020, subject to certain exceptions.
|
The settlement agreement does not prevent us from asserting any claim, cross-claim, defense, or other cause of action against Shell Energy, nor does the settlement agreement prevent Shell Energy from asserting any claim, cross-claim, defense, or other cause of action against us. Furthermore, the settlement agreement provides that it shall not affect any proof of claim that Shell Energy filed in the Chapter 11 Cases. As of December 31, 2017, we had a receivable of approximately
$33.4 million
related to the sales of natural gas to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. Shell Energy is withholding payment as a means to satisfy their demands of reasonable assurance of
performance under a natural gas sales agreement. We believe the request for adequate assurance was unreasonable and unjustified under the terms of the agreement and these amounts have been improperly withheld by Shell Energy. On March 7, 2018, the Court approved the rejection of the aforementioned natural gas sales agreement with Shell Energy and we recorded a liability of
$41.5 million
in “Liabilities subject to compromise” related to our current estimate of the allowed claim. The receivable for sales of oil and natural gas to Shell Energy in November and December 2017 and the estimate of the allowed claim for the rejection of the natural gas sales agreement with Shell Energy were presented as a net amount of
$8.1 million
in "Liabilities subject to compromise" as of December 31, 2018. See further discussion regarding this dispute with Shell Energy in "Item 3. Legal proceedings".
|
|
9.
|
Employee benefit plans
|
We sponsor a 401(k) plan for our employees which matches
100%
of employee contributions up to certain limits. For the year ended December 31, 2018, the Company's matching contribution was up to a maximum of
4%
of each employee's pay. For the year ended December 31, 2017, the Company's matching contribution was up to a maximum of
3%
of each employee's pay. Our matching contributions were
$0.7 million
and
$0.6 million
for the
years ended December 31, 2018 and 2017
, respectively. Effective January 1, 2019, the Company increased its matching contribution up to a maximum of
5%
of each employee's pay.
10.
Earnings (loss) per share
The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split on June 12, 2017, for the
years ended December 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands, except per share data)
|
|
2018
|
|
2017
|
Basic net income (loss) per common share:
|
|
|
|
|
Net income (loss)
|
|
$
|
(182,697
|
)
|
|
$
|
24,362
|
|
Weighted average common shares outstanding
|
|
21,686
|
|
|
21,288
|
|
Net income (loss) per basic common share
|
|
$
|
(8.42
|
)
|
|
$
|
1.14
|
|
Diluted net income (loss) per common share:
|
|
|
|
|
Net income (loss)
|
|
$
|
(182,697
|
)
|
|
$
|
24,362
|
|
Weighted average common shares outstanding
|
|
21,686
|
|
|
21,288
|
|
Dilutive effect of:
|
|
|
|
|
Restricted shares and restricted share units
|
|
—
|
|
|
—
|
|
Weighted average common shares and common share equivalents outstanding
|
|
21,686
|
|
|
21,288
|
|
Net income (loss) per diluted common share
|
|
$
|
(8.42
|
)
|
|
$
|
1.14
|
|
Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, the Commitment Fee and Amendment Fee Warrants, which represent the right to purchase our common shares at an exercise price of
$0.01
are included in our weighted average common shares outstanding and used in the computation of our basic net income (loss) per common share. On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the Commitment Fee and Amendment Fee Warrants. See "
Note 13. Related-party transactions
" for additional information on the warrants issued to Fairfax.
Diluted net income (loss) per common share for the
years ended December 31, 2018 and 2017
is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards, Financing Warrants, and ESAS Warrants, whether exercisable or not. The computation of diluted net income (loss) per common share excluded
11,251,824
and
12,907,872
antidilutive common share equivalents for the
years ended December 31, 2018 and 2017
, respectively. The antidilutive common share equivalents for the
years ended December 31, 2018 and 2017
primarily related to the Financing Warrants.
11.
Equity-based and other incentive-based compensation
Key Employee Incentive Plan, Key Employee Retention Plan, and Prepaid Retention Plans
In connection with our review of strategic alternatives during late 2017, the Compensation Committee of the Board of Directors (“Compensation Committee”) determined that (i) normal annual and long-term incentive cycles are likely to be ineffective due to our ongoing strategic restructuring efforts and (ii) the use of equity compensation is currently ineffective and inefficient. As a result, the Compensation Committee and the Company restructured our incentive plans to retain employees and align the interests of employees with our stakeholders. We implemented the following changes to our compensation plans:
|
|
•
|
Termination of the 2017 Management Incentive Plan
- We terminated the 2017 Management Incentive Plan and made pro-rated incentive payments based on the achievement of performance goals as of June 30, 2017. The payments of
$1.1 million
were made in cash.
|
|
|
•
|
Adoption of the KEIP and KERP
- We adopted two new cash-based incentive programs beginning on July 1, 2017, including the Key Employee Incentive Plan ("KEIP") for certain officers and Key Employee Retention Plan ("KERP") for employees. The payout of the KEIP is dependent on the achievement of certain performance goals, including production, general and administrative expenses, lease operating expenses, and EBITDA. The payout of the KERP was dependent on the achievement of these performance measures and a fixed percentage of the employees' salary for the first two quarters of the plan until it was converted to be solely based on a fixed percentage of the employees' salary. We incurred
$4.8 million
in general and administrative expenses related to these plans during 2017. The motion to consider the KERP was approved by the Court on February 22, 2018 and the motion to consider the KEIP was approved by the Court on May 23, 2018. We incurred
$4.8 million
in general administrative expenses related to these plans during 2018. The KERP is paid on a quarterly basis and the KEIP earned during 2018 will not be paid until the confirmation of a plan of reorganization. Therefore, we accrued
$2.2 million
related to the KEIP as of December 31, 2018. The term of the KERP was extended to December 31, 2018 and may be extended further at the discretion of the Compensation Committee or the Company, which would be subject to approval as part of the Chapter 11 Cases. The term of the KEIP was extended to December 31, 2018 and further extensions, if any, would be subject to approval as part of the Chapter 11 Cases.
|
|
|
•
|
Retention Bonus Agreements
- We entered into retention bonus agreements with certain key officers and employees, which resulted in payments of
$0.8 million
and
$7.8 million
during 2018 and 2017, respectively. In the event a recipient of a retention bonus voluntarily terminates his or her employment without Good Reason (as defined in each Retention Bonus Agreement), or the Company terminates such recipient’s employment for Cause (as defined in each Retention Bonus Agreement), in either case, before either December 31, 2018 or March 31, 2019 (depending on the agreement with the officer or employee), then such recipient will be required to promptly repay the retention bonus. We recognized
$6.3 million
and
$1.4 million
of general and administrative expenses related to these retention bonuses during 2018 and 2017, respectively. The remainder of
$0.9 million
was recorded as a prepaid asset as of December 31, 2018 and will be recognized over the remaining retention period ending March 31, 2019.
|
|
|
•
|
Discontinuation of equity incentive grants
- We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there were no grants of share-based compensation during 2018 or 2017. The adoption of the KEIP, KERP and retention bonuses were intended to replace all existing cash-based bonus and equity-based compensation programs.
|
Share-based compensation
Description of plan
Our 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to
3,033,333
restricted shares, restricted share units and stock options. As of
December 31, 2018
and
2017
, there were
1,376,008
and
1,140,543
shares, respectively, available for issuance under the 2005 Incentive Plan. Option grants and restricted share grants count as one share and
1.74
shares, respectively, against the total number of shares available for grant. The holders of restricted shares, excluding restricted share units ("RSU") discussed below, had voting rights, and upon vesting, the right to receive all accrued and unpaid dividends.
We believe it is highly likely that our existing common shares and share-based compensation will be canceled at the conclusion of our Chapter 11 proceedings and holders are not expected to be entitled to any recovery. See "Item 1A. Risk Factors" for additional information.
Market-based restricted share awards
Certain RSU's granted to our officers and certain employees have vesting percentages between
0%
and
200%
depending on EXCO's total shareholder return in comparison to an identified peer group. Our market-based restricted share units are valued on the date of grant and vest over a range of
three
years, subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method.
The Company has discretion to convert certain vested awarded units, if any, into a cash payment equal to the fair market value of a share of common stock, multiplied by the number of vested units, or the number of whole shares of common stock equal to the number of vested units, if any. These RSUs met the criteria for equity classification per ASC 718.
The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. The assumptions used in the Monte Carlo model for the RSUs granted in 2016 are as follows:
|
|
|
|
Assumption
|
|
2016
|
Risk-free rate of return
|
|
0.45 - 0.71 %
|
Volatility
|
|
119.83 %
|
Dividend yield
|
|
0.00 %
|
A summary of our market-based restricted share activity for RSUs during the year ended
December 31, 2018
is as follows:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
|
|
Non-vested shares/units outstanding at December 31, 2017
|
|
249,992
|
|
|
$
|
29.96
|
|
Granted
|
|
—
|
|
|
—
|
|
Vested
|
|
—
|
|
|
—
|
|
Forfeited
|
|
(3,200
|
)
|
|
25.39
|
|
Non-vested shares/units outstanding at December 31, 2018
|
|
246,792
|
|
|
$
|
30.02
|
|
ESAS Warrants
On September 8, 2015, EXCO issued warrants to ESAS as an additional performance incentive for services performed under a services and investment agreement. The ESAS Warrants were issued in
four
tranches to purchase an aggregate of
5,333,335
common shares, subject to certain time-based vesting criteria and EXCO's total shareholder return in comparison to an identified peer group. See further discussion of the ESAS Warrants in "Note 13. Related party transactions".
Equity-based compensation costs
All of our stock options, restricted shares and certain RSUs are accounted for in accordance with ASC 718 and are classified as equity. As required by ASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital.
Total share-based compensation to employees to be recognized on unvested options, restricted share awards and RSUs as of
December 31, 2018
was
$0.9 million
and will be recognized over a weighted average period of
0.5
years.
The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the ESAS Warrants to be re-measured each interim reporting period and an adjustment was recorded in the statement of operations within equity-based compensation expense. Concurrently with the suspension of the services and investment agreement with ESAS, on November 9, 2017, the ESAS Warrants were forfeited and canceled and previously recognized compensation costs were reversed. For the year ended December 31, 2017, equity-based compensation related to the ESAS Warrants was income of
$14.5 million
.
The following is a reconciliation of our compensation expense for the
years ended December 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Equity-based compensation expense (1)
|
|
$
|
2,053
|
|
|
$
|
(11,430
|
)
|
Equity-based compensation capitalized
|
|
347
|
|
|
1,000
|
|
Total equity-based compensation
|
|
$
|
2,400
|
|
|
$
|
(10,430
|
)
|
|
|
(1)
|
Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for ESAS Warrants.
|
We did not recognize a tax benefit attributable to our equity-based compensation for the
years ended December 31, 2018 and 2017
.
The income tax provision attributable to our income (loss) before income taxes for the
years ended December 31, 2018 and 2017
, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Current:
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
(1,420
|
)
|
State
|
|
—
|
|
|
—
|
|
Total current income tax (benefit)
|
|
$
|
—
|
|
|
$
|
(1,420
|
)
|
|
|
|
|
|
Deferred:
|
|
|
|
|
Federal
|
|
$
|
(34,884
|
)
|
|
$
|
528,886
|
|
State
|
|
(1,028
|
)
|
|
(1,496
|
)
|
Valuation allowance
|
|
31,394
|
|
|
(525,674
|
)
|
Total deferred income tax (benefit)
|
|
(4,518
|
)
|
|
1,716
|
|
Total income tax (benefit)
|
|
$
|
(4,518
|
)
|
|
$
|
296
|
|
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Act") which, among other things, lowered the U.S. Federal tax rate from
35%
to
21%
, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We reflected the impact of this rate on our deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. As a result of the Tax Act and monetization opportunities under current law, we have credits that were refunded in late 2017 and the remainder are expected to be refunded in 2019. In addition, the Tax Act limits the amount taxpayers are able to deduct for NOLs generated in taxable years beginning after December 31, 2017 to
80%
of the taxpayer’s taxable income. The law also generally repeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending after December 31, 2017 can be carried forward indefinitely. On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides a one-year measurement period from a registrant's reporting period that includes the Tax Act's enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. We completed our analysis of the impact of the Tax Act during 2018 and the impact of any changes are reflected in our deferred tax assets and liabilities at December 31, 2018. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.
We have NOLs for U.S. income tax purposes that have been generated from our operations. Our NOLs generated prior to 2018 are scheduled to expire if not utilized between 2028 and 2037. We reduced our NOLs by the amount of cancellation of debt income of approximately
$86.6 million
related to certain debt restructuring transactions during the year ended December 31, 2017.
The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change based on the criteria in Section 382 of the Internal Revenue Code. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one or more five-percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing date within a three-year period. See further discussion of the potential limitations on the utilization of our net operating losses as part of "Item 1A. Risk Factors". The Internal Revenue Code permits the exclusion of cancellation of debt income from taxable income if the discharge occurs during a Chapter 11 case. If this occurs, the amount of cancellation of debt income would reduce a company's tax attributes unless it is offset by NOLs. The NOLs that are available to offset cancellation of debt income in a Chapter 11 case are not limited by Section 382 of the Internal Revenue Code. NOLs available for utilization as of
December 31, 2018
were approximately
$2.2 billion
.
There is an exception to the foregoing annual limitation rules for entities in bankruptcy that generally applies when “qualified creditors” of a debtor corporation receive, in respect of their claims, at least 50% of the voting rights and value of the equity of the reorganized debtor pursuant to a confirmed chapter 11 plan (the “382(l)(5) Exception”). Under the 382(l)(5) Exception, a debtor’s NOLs prior to the ownership change are not limited on an annual basis, but, instead, NOL carryforwards will be reduced by the amount of any interest deductions claimed during the three taxable years preceding the effective date of the plan of reorganization, and during the part of the taxable year prior to and including the effective date of the plan of reorganization, in respect of all debt converted into equity in the reorganization. If the 382(l)(5) Exception applies and the reorganized debtors undergo another “ownership change” within two years after the effective date of the plan of reorganization, then the reorganized debtors’ losses prior to the ownership change would effectively be eliminated in their entirety.
If we are eligible for the 382(l)(5) Exception, we currently anticipate that we would not elect out of its application in order to preserve the Company’s tax attributes. However, it is uncertain whether the structure of the March 2019 Plan or an alternative plan of reorganization would allow us to qualify for the 382(l)(5) Exception. Therefore, we cannot provide any assurance regarding the extent of limitations on the Company’s tax attributes upon emergence from bankruptcy.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2018
|
|
December 31, 2017
|
Deferred tax assets:
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
568,976
|
|
|
$
|
548,701
|
|
Oil and natural gas properties, gathering assets, and equipment
|
|
178,498
|
|
|
236,601
|
|
Liabilities subject to compromise
|
|
92,954
|
|
|
—
|
|
Other
|
|
43,149
|
|
|
58,465
|
|
Total deferred tax assets before valuation allowance
|
|
883,577
|
|
|
843,767
|
|
Valuation allowance
|
|
(874,877
|
)
|
|
(843,480
|
)
|
Total deferred tax assets
|
|
8,700
|
|
|
287
|
|
Deferred tax liabilities:
|
|
|
|
|
Goodwill
|
|
$
|
(7,205
|
)
|
|
$
|
(4,518
|
)
|
Derivative financial instruments
|
|
—
|
|
|
(287
|
)
|
Other
|
|
(1,495
|
)
|
|
—
|
|
Total deferred tax liabilities
|
|
(8,700
|
)
|
|
(4,805
|
)
|
Net deferred tax assets (liabilities)
|
|
$
|
—
|
|
|
$
|
(4,518
|
)
|
As previously discussed, we reflected the impact of the change in the tax rate as a result of the Tax Act on our deferred tax assets and liabilities at December 31, 2017. During the
years ended December 31, 2018 and 2017
, we recognized a full valuation allowance against our net deferred tax assets.
A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the
years ended December 31, 2018 and 2017
is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Federal income taxes (benefit) provision at statutory rate
|
|
$
|
(39,315
|
)
|
|
$
|
8,630
|
|
Increases (reductions) resulting from:
|
|
|
|
|
Adjustments to the valuation allowance
|
|
31,394
|
|
|
(525,674
|
)
|
Non-deductible compensation
|
|
—
|
|
|
3,206
|
|
State taxes net of federal benefit
|
|
(1,028
|
)
|
|
(1,496
|
)
|
Federal and state tax rate change
|
|
—
|
|
|
421,610
|
|
Non-deductible interest
|
|
4,814
|
|
|
149,577
|
|
Non-taxable gain on warrants
|
|
(397
|
)
|
|
(55,716
|
)
|
Other
|
|
14
|
|
|
159
|
|
Total income tax provision
|
|
$
|
(4,518
|
)
|
|
$
|
296
|
|
During the year ended December 31, 2017, we recognized a current income tax benefit of
$1.4 million
due to refunds for alternative minimum tax credits. During the
years ended December 31, 2018 and 2017
, we recognized deferred income tax benefit of
$4.5 million
and expense of
$1.7 million
, respectively, related to a deferred tax liability for tax deductible goodwill. Deferred income tax benefit during the
year ended December 31, 2018
related to changes in a deferred tax liability for tax-deductible goodwill. As of December 31, 2017, we recognized a deferred tax liability of
$4.5 million
for tax-deductible goodwill. The deferred tax liability related to goodwill was considered to have an indefinite life based on the nature of the underlying asset and could not be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. As a result of the Tax Act, deferred tax assets resulting from NOLs generated in taxable years subsequent to December 31, 2017 are considered to have an indefinite life. Therefore, we recognized an income tax benefit of
$4.5 million
during the in the first quarter of 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill.
We did not recognize any liabilities for unrecognized tax benefits. As of
December 31, 2018
and
2017
, our policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. We have not accrued any interest or penalties relating to unrecognized tax benefits in the Consolidated Financial Statements.
We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax returns in various states. With few exceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2009.
|
|
13.
|
Related party transactions
|
ESAS
On March 31, 2015, we entered into a services and investment agreement with ESAS, a wholly owned subsidiary of an affiliate of Bluescape. C. John Wilder, Executive Chairman of Bluescape, was the Executive Chairman of our Board of Directors until his resignation on November 9, 2017, and indirectly controls ESAS. As consideration for the services provided under the agreement, EXCO paid ESAS a monthly fee of
$300,000
and an annual incentive payment of up to
$2.4 million
per year that was based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group. As an additional performance incentive under the services and investment agreement, EXCO issued ESAS Warrants in
four
tranches to purchase an aggregate of
5,333,335
common shares, subject to the satisfaction of certain performance criteria, at exercise prices ranging from
$41.25
per share to
$150.00
per share. The number of shares and exercise prices have been adjusted to reflect the reverse share-split that occurred on June 2, 2017.
On September 20, 2017, ESAS received
$4.0 million
and
$1.8 million
of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in ESAS holding
$74.0 million
in aggregate principal amount of 1.5 Lien Notes and
$49.7 million
in aggregate principal amount of 1.75 Lien Term Loans as of
December 31, 2018
and 2017. During the year ended December 31, 2017, ESAS also received
$1.2 million
of cash interest payments on the Exchange Term Loan and
192,609
of PIK Shares under the 1.75 Lien Term Loans. In addition, ESAS holds Financing Warrants representing the
right to purchase an aggregate of
5,017,922
common shares at an exercise price equal to
$13.95
per share. ESAS received a consent fee of
$1.6 million
in cash for exchanging its interest in the Exchange Term Loan, and a commitment fee of
$2.1 million
in cash in connection with the issuance of the 1.5 Lien Notes.
On November 9, 2017, we entered into an agreement with ESAS pursuant to which, among other things: (i) the services and investment agreement with ESAS was suspended such that, during the suspension period and subject to the terms and conditions of the agreement: (a) ESAS is not required to provide any services to us, (b) we are not required to make any payments to ESAS with respect to the suspension period and (c) ESAS does not have the right to nominate a member to the Company’s Board of Directors; and (ii) the ESAS Warrants were forfeited and canceled and we have no further obligations under the ESAS Warrants. Prior to the suspension, the payments to ESAS as part of the services and investment agreement were
$3.4 million
for the year ended December 31, 2017.
On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Bluescape. See "
Note 5. Debt
" for further discussion of the DIP Credit Agreement.
Fairfax
Samuel Mitchell served as a Managing Director of Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa"), the investment manager of Fairfax and certain affiliates thereof. Samuel Mitchell was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, certain affiliates of Fairfax received
$8.5 million
and
$15.8 million
of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in Fairfax holding, directly or indirectly,
$159.5 million
in aggregate principal amount of 1.5 Lien Notes and
$427.9 million
in aggregate principal amount of 1.75 Lien Term Loans as of December 31, 2018 and 2017. During the year ended December 31, 2017, Fairfax also received
$10.6 million
of cash interest payments on the Fairfax Term Loan and the Exchange Term Loan and
1,657,330
of PIK Shares under the 1.75 Lien Term Loans. In addition, Fairfax holds Financing Warrants representing the right to purchase an aggregate of
10,824,377
common shares at an exercise price equal to
$13.95
per share, Commitment Fee Warrants representing the right to purchase an aggregate of
431,433
common shares at an exercise price equal to
$0.01
per share and Amendment Fee Warrants representing the right to purchase an aggregate of
1,294,143
common shares at an exercise price equal to
$0.01
per share. On January 16, 2018, affiliates of Fairfax surrendered all of their rights in the 2017 Warrants.
On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax. See "Note 5. Debt" further discussion of the DIP Credit Agreement.
Oaktree
B. James Ford served as a Senior Advisor of Oaktree, and was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, Oaktree received
$2.2 million
of PIK Payments in the form of additional 1.5 Lien Notes resulting in certain affiliates of Oaktree holding, directly or indirectly,
$41.7 million
in aggregate principal amount of 1.5 Lien Notes as of December 31, 2018 and 2017. In addition, certain affiliates of Oaktree hold Financing Warrants representing the right to purchase an aggregate of
2,831,542
common shares at an exercise price equal to
$13.95
per share. Oaktree also received a commitment fee of
$1.2 million
in cash in connection with the issuance of the 1.5 Lien Notes.
|
|
14.
|
Condensed consolidating financial statements
|
As of
December 31, 2018
, the majority of EXCO’s subsidiaries were guarantors under the DIP Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit agreement governing the 1.75 Lien Term Loans, the credit agreement governing the Second Lien Term Loans, and the indentures governing the 2018 Notes and 2022 Notes. All of our unrestricted subsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The DIP Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries. Resources and the Guarantor Subsidiaries solely consist of entities that are Debtors in the Chapter 11 Cases, including each of the Filing Subsidiaries. The non-guarantor subsidiaries solely consist of entities that are not included in the Chapter 11 Cases, including OPCO, Appalachia Midstream, EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC and certain other entities (referred to as Non-Guarantor Subsidiaries).
The following financial information presents consolidating financial statements, which include:
|
|
•
|
the Guarantor Subsidiaries;
|
|
|
•
|
the Non-Guarantor Subsidiaries;
|
|
|
•
|
elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and
|
|
|
•
|
EXCO on a consolidated basis.
|
Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
47,269
|
|
|
$
|
(20,059
|
)
|
|
$
|
19,331
|
|
|
$
|
—
|
|
|
$
|
46,541
|
|
Restricted cash
|
|
653
|
|
|
15,396
|
|
|
—
|
|
|
—
|
|
|
16,049
|
|
Other current assets
|
|
6,671
|
|
|
93,305
|
|
|
7,577
|
|
|
—
|
|
|
107,553
|
|
Total current assets
|
|
54,593
|
|
|
88,642
|
|
|
26,908
|
|
|
—
|
|
|
170,143
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
4,732
|
|
|
—
|
|
|
4,732
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
121,738
|
|
|
33,908
|
|
|
—
|
|
|
155,646
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
334,709
|
|
|
2,924,788
|
|
|
73,282
|
|
|
—
|
|
|
3,332,779
|
|
Accumulated depletion
|
|
(330,776
|
)
|
|
(2,494,452
|
)
|
|
(6,065
|
)
|
|
—
|
|
|
(2,831,293
|
)
|
Oil and natural gas properties, net
|
|
3,933
|
|
|
552,074
|
|
|
101,125
|
|
|
—
|
|
|
657,132
|
|
Other property and equipment, net and other non-current assets
|
|
587
|
|
|
19,565
|
|
|
17,379
|
|
|
—
|
|
|
37,531
|
|
Investments in and (advances to) affiliates, net
|
|
379,516
|
|
|
—
|
|
|
—
|
|
|
(379,516
|
)
|
|
—
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
Total assets
|
|
$
|
451,922
|
|
|
$
|
810,143
|
|
|
$
|
150,144
|
|
|
$
|
(379,516
|
)
|
|
$
|
1,032,693
|
|
Liabilities and shareholders’ equity
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
473,364
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
473,364
|
|
Other current liabilities
|
|
38,343
|
|
|
71,802
|
|
|
7,784
|
|
|
—
|
|
|
117,929
|
|
Other long-term liabilities
|
|
—
|
|
|
14,825
|
|
|
9,588
|
|
|
—
|
|
|
24,413
|
|
Liabilities subject to compromise
|
|
966,711
|
|
|
476,772
|
|
|
—
|
|
|
—
|
|
|
1,443,483
|
|
Payable to parent
|
|
—
|
|
|
2,452,128
|
|
|
(3,380
|
)
|
|
(2,448,748
|
)
|
|
—
|
|
Total shareholders’ equity
|
|
(1,026,496
|
)
|
|
(2,205,384
|
)
|
|
136,152
|
|
|
2,069,232
|
|
|
(1,026,496
|
)
|
Total liabilities and shareholders’ equity
|
|
$
|
451,922
|
|
|
$
|
810,143
|
|
|
$
|
150,144
|
|
|
$
|
(379,516
|
)
|
|
$
|
1,032,693
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
49,170
|
|
|
$
|
(9,573
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
39,597
|
|
Restricted cash
|
|
—
|
|
|
15,271
|
|
|
—
|
|
|
—
|
|
|
15,271
|
|
Other current assets
|
|
22,697
|
|
|
90,265
|
|
|
—
|
|
|
—
|
|
|
112,962
|
|
Total current assets
|
|
71,867
|
|
|
95,963
|
|
|
—
|
|
|
—
|
|
|
167,830
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
14,181
|
|
|
—
|
|
|
14,181
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
118,652
|
|
|
—
|
|
|
—
|
|
|
118,652
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
333,719
|
|
|
2,773,847
|
|
|
—
|
|
|
—
|
|
|
3,107,566
|
|
Accumulated depletion
|
|
(330,777
|
)
|
|
(2,421,534
|
)
|
|
—
|
|
|
—
|
|
|
(2,752,311
|
)
|
Oil and natural gas properties, net
|
|
2,942
|
|
|
470,965
|
|
|
—
|
|
|
—
|
|
|
473,907
|
|
Other property and equipment, net and other non-current assets
|
|
892
|
|
|
20,382
|
|
|
—
|
|
|
—
|
|
|
21,274
|
|
Investments in and (advances to) affiliates, net
|
|
466,055
|
|
|
—
|
|
|
—
|
|
|
(466,055
|
)
|
|
—
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
Total assets
|
|
$
|
555,049
|
|
|
$
|
737,172
|
|
|
$
|
14,181
|
|
|
$
|
(466,055
|
)
|
|
$
|
840,347
|
|
Liabilities and shareholders’ equity
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
1,362,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,362,500
|
|
Other current liabilities
|
|
32,280
|
|
|
272,190
|
|
|
—
|
|
|
—
|
|
|
304,470
|
|
Derivative financial instruments - common share warrants
|
|
1,950
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,950
|
|
Other long-term liabilities
|
|
4,518
|
|
|
13,108
|
|
|
—
|
|
|
—
|
|
|
17,626
|
|
Payable to parent
|
|
—
|
|
|
2,447,586
|
|
|
—
|
|
|
(2,447,586
|
)
|
|
—
|
|
Total shareholders’ equity
|
|
(846,199
|
)
|
|
(1,995,712
|
)
|
|
14,181
|
|
|
1,981,531
|
|
|
(846,199
|
)
|
Total liabilities and shareholders’ equity
|
|
$
|
555,049
|
|
|
$
|
737,172
|
|
|
$
|
14,181
|
|
|
$
|
(466,055
|
)
|
|
$
|
840,347
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
352,228
|
|
|
$
|
20,363
|
|
|
$
|
—
|
|
|
$
|
372,591
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
21,090
|
|
|
345
|
|
|
—
|
|
|
21,435
|
|
Total revenues
|
|
—
|
|
|
373,318
|
|
|
20,708
|
|
|
—
|
|
|
394,026
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
54,431
|
|
|
2,978
|
|
|
—
|
|
|
57,409
|
|
Gathering and transportation
|
|
—
|
|
|
72,772
|
|
|
3,403
|
|
|
—
|
|
|
76,175
|
|
Purchased natural gas
|
|
—
|
|
|
16,387
|
|
|
—
|
|
|
—
|
|
|
16,387
|
|
Depletion, depreciation and amortization
|
|
299
|
|
|
73,305
|
|
|
6,685
|
|
|
—
|
|
|
80,289
|
|
Accretion of liabilities
|
|
—
|
|
|
931
|
|
|
1,066
|
|
|
—
|
|
|
1,997
|
|
General and administrative
|
|
(34,637
|
)
|
|
58,296
|
|
|
4,191
|
|
|
—
|
|
|
27,850
|
|
Gain on Appalachia JV Settlement
|
|
—
|
|
|
—
|
|
|
(119,237
|
)
|
|
—
|
|
|
(119,237
|
)
|
Other operating items
|
|
(46
|
)
|
|
(1,109
|
)
|
|
(170
|
)
|
|
—
|
|
|
(1,325
|
)
|
Total costs and expenses
|
|
(34,384
|
)
|
|
275,013
|
|
|
(101,084
|
)
|
|
—
|
|
|
139,545
|
|
Operating income
|
|
34,384
|
|
|
98,305
|
|
|
121,792
|
|
|
—
|
|
|
254,481
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(33,917
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(33,917
|
)
|
Loss on derivative financial instruments - commodity derivatives
|
|
(615
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(615
|
)
|
Gain on derivative financial instruments - common share warrants
|
|
1,889
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,889
|
|
Other income
|
|
27
|
|
|
37
|
|
|
6
|
|
|
—
|
|
|
70
|
|
Equity income
|
|
—
|
|
|
—
|
|
|
175
|
|
|
—
|
|
|
175
|
|
Reorganization items, net
|
|
(101,284
|
)
|
|
(308,014
|
)
|
|
—
|
|
|
—
|
|
|
(409,298
|
)
|
Net loss from consolidated subsidiaries
|
|
(87,699
|
)
|
|
—
|
|
|
—
|
|
|
87,699
|
|
|
—
|
|
Total other income (expense)
|
|
(221,599
|
)
|
|
(307,977
|
)
|
|
181
|
|
|
87,699
|
|
|
(441,696
|
)
|
Income (loss) before income taxes
|
|
(187,215
|
)
|
|
(209,672
|
)
|
|
121,973
|
|
|
87,699
|
|
|
(187,215
|
)
|
Income tax benefit
|
|
(4,518
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,518
|
)
|
Net income (loss)
|
|
$
|
(182,697
|
)
|
|
$
|
(209,672
|
)
|
|
$
|
121,973
|
|
|
$
|
87,699
|
|
|
$
|
(182,697
|
)
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
258,830
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
258,830
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
24,816
|
|
|
—
|
|
|
—
|
|
|
24,816
|
|
Total revenues
|
|
—
|
|
|
283,646
|
|
|
—
|
|
|
—
|
|
|
283,646
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
48,142
|
|
|
—
|
|
|
—
|
|
|
48,142
|
|
Gathering and transportation
|
|
—
|
|
|
111,427
|
|
|
—
|
|
|
—
|
|
|
111,427
|
|
Purchased natural gas
|
|
—
|
|
|
23,400
|
|
|
—
|
|
|
—
|
|
|
23,400
|
|
Depletion, depreciation and amortization
|
|
298
|
|
|
50,742
|
|
|
—
|
|
|
—
|
|
|
51,040
|
|
Accretion of liabilities
|
|
—
|
|
|
874
|
|
|
—
|
|
|
—
|
|
|
874
|
|
General and administrative
|
|
(30,224
|
)
|
|
60,389
|
|
|
—
|
|
|
—
|
|
|
30,165
|
|
Other operating items
|
|
553
|
|
|
58,601
|
|
|
—
|
|
|
—
|
|
|
59,154
|
|
Total costs and expenses
|
|
(29,373
|
)
|
|
353,575
|
|
|
—
|
|
|
—
|
|
|
324,202
|
|
Operating income (loss)
|
|
29,373
|
|
|
(69,929
|
)
|
|
—
|
|
|
—
|
|
|
(40,556
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(108,173
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(108,175
|
)
|
Gain on derivative financial instruments - commodity derivatives
|
|
24,732
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,732
|
|
Gain on derivative financial instruments - common share warrants
|
|
159,190
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
159,190
|
|
Loss on restructuring of debt
|
|
(6,380
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,380
|
)
|
Other income
|
|
30
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
31
|
|
Equity loss
|
|
—
|
|
|
—
|
|
|
(4,184
|
)
|
|
—
|
|
|
(4,184
|
)
|
Net loss from consolidated subsidiaries
|
|
(74,114
|
)
|
|
—
|
|
|
—
|
|
|
74,114
|
|
|
—
|
|
Total other income (expense)
|
|
(4,715
|
)
|
|
(1
|
)
|
|
(4,184
|
)
|
|
74,114
|
|
|
65,214
|
|
Income (loss) before income taxes
|
|
24,658
|
|
|
(69,930
|
)
|
|
(4,184
|
)
|
|
74,114
|
|
|
24,658
|
|
Income tax expense
|
|
296
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
296
|
|
Net income (loss)
|
|
$
|
24,362
|
|
|
$
|
(69,930
|
)
|
|
$
|
(4,184
|
)
|
|
$
|
74,114
|
|
|
$
|
24,362
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(22,984
|
)
|
|
$
|
148,311
|
|
|
$
|
8,669
|
|
|
$
|
—
|
|
|
$
|
133,996
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(1,047
|
)
|
|
(164,164
|
)
|
|
14,044
|
|
|
—
|
|
|
(151,167
|
)
|
Other
|
|
—
|
|
|
950
|
|
|
—
|
|
|
—
|
|
|
950
|
|
Advances/investments with affiliates
|
|
(1,160
|
)
|
|
4,542
|
|
|
(3,382
|
)
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) investing activities
|
|
(2,207
|
)
|
|
(158,672
|
)
|
|
10,662
|
|
|
—
|
|
|
(150,217
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under DIP Credit Agreement
|
|
156,406
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156,406
|
|
Repayments under EXCO Resources Credit Agreement
|
|
(126,401
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(126,401
|
)
|
Debt financing costs and other
|
|
(6,062
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,062
|
)
|
Net cash provided by financing activities
|
|
23,943
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,943
|
|
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
(1,248
|
)
|
|
(10,361
|
)
|
|
19,331
|
|
|
—
|
|
|
7,722
|
|
Cash, cash equivalents and restricted cash at beginning of period
|
|
49,170
|
|
|
5,698
|
|
|
—
|
|
|
—
|
|
|
54,868
|
|
Cash, cash equivalents and restricted cash at end of period
|
|
$
|
47,922
|
|
|
$
|
(4,663
|
)
|
|
$
|
19,331
|
|
|
$
|
—
|
|
|
$
|
62,590
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(22,761
|
)
|
|
$
|
77,172
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
54,411
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(1,347
|
)
|
|
(169,820
|
)
|
|
—
|
|
|
—
|
|
|
(171,167
|
)
|
Proceeds from disposition of property and equipment
|
|
—
|
|
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
Net changes in amounts due to joint ventures
|
|
—
|
|
|
(9,161
|
)
|
|
—
|
|
|
—
|
|
|
(9,161
|
)
|
Equity investments and other
|
|
—
|
|
|
1,548
|
|
|
—
|
|
|
—
|
|
|
1,548
|
|
Advances/investments with affiliates
|
|
(110,001
|
)
|
|
110,001
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net cash used in investing activities
|
|
(111,348
|
)
|
|
(67,082
|
)
|
|
—
|
|
|
—
|
|
|
(178,430
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under EXCO Resources Credit Agreement
|
|
163,401
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
163,401
|
|
Repayments under EXCO Resources Credit Agreement
|
|
(265,592
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265,592
|
)
|
Proceeds received from issuance of 1.5 Lien Notes, net
|
|
295,530
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
295,530
|
|
Payments on Second Lien Term Loans
|
|
(11,602
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,602
|
)
|
Payments of common share dividends
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Debt financing costs and other
|
|
(23,062
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23,062
|
)
|
Net cash provided by financing activities
|
|
158,669
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
158,669
|
|
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
24,560
|
|
|
10,090
|
|
|
—
|
|
|
—
|
|
|
34,650
|
|
Cash, cash equivalents and restricted cash at beginning of period
|
|
24,610
|
|
|
(4,392
|
)
|
|
—
|
|
|
—
|
|
|
20,218
|
|
Cash, cash equivalents and restricted cash at end of period
|
|
$
|
49,170
|
|
|
$
|
5,698
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
54,868
|
|
|
|
15.
|
Quarterly financial data (unaudited)
|
The following are summarized quarterly financial data for the
years ended December 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
(in thousands, except per share amounts)
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
2018
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
90,464
|
|
|
$
|
98,130
|
|
|
$
|
98,571
|
|
|
$
|
106,861
|
|
Operating income (loss) (1)
|
|
146,737
|
|
|
30,399
|
|
|
31,121
|
|
|
46,224
|
|
Net income (loss)
|
|
$
|
(211,049
|
)
|
|
$
|
7,744
|
|
|
$
|
3,684
|
|
|
$
|
16,924
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(9.64
|
)
|
|
$
|
0.36
|
|
|
$
|
0.17
|
|
|
$
|
0.78
|
|
Weighted average shares
|
|
21,902
|
|
|
21,615
|
|
|
21,616
|
|
|
21,616
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(9.64
|
)
|
|
$
|
0.36
|
|
|
$
|
0.17
|
|
|
$
|
0.78
|
|
Weighted average shares
|
|
21,902
|
|
|
21,615
|
|
|
21,616
|
|
|
21,616
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
76,529
|
|
|
$
|
71,015
|
|
|
$
|
66,736
|
|
|
$
|
69,366
|
|
Operating income (loss) (2)
|
|
13,587
|
|
|
15,216
|
|
|
(5,142
|
)
|
|
(64,217
|
)
|
Net income (loss) (3)
|
|
$
|
8,193
|
|
|
$
|
120,750
|
|
|
$
|
(18,824
|
)
|
|
$
|
(85,757
|
)
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.44
|
|
|
$
|
6.13
|
|
|
$
|
(0.81
|
)
|
|
$
|
(3.68
|
)
|
Weighted average shares
|
|
18,726
|
|
|
19,702
|
|
|
23,319
|
|
|
23,333
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.44
|
|
|
$
|
6.07
|
|
|
$
|
(0.81
|
)
|
|
$
|
(3.68
|
)
|
Weighted average shares
|
|
18,749
|
|
|
19,886
|
|
|
23,319
|
|
|
23,333
|
|
|
|
(
1)
|
Operating income for the first quarter of 2018 includes the gain of
$119.5
million recognized in connection with the Appalachia JV Settlement. Operating income during 2018 was significantly impacted by costs associated with the Chapter 11 process, which includes
$352.9 million
,
$16.4 million
,
$18.2 million
and
$21.8 million
during the first, second, third, and fourth quarters of 2018, respectively, that were classified as “Reorganization items, net” in our Consolidated Statement of Operations. See "Note 1. Organization and basis of presentation" for further discussion.
|
|
|
(2)
|
Operating loss for the fourth quarter of 2017 includes the acceleration of the remaining charges under a firm transportation agreement of
$56.4 million
. See "Note 8. Commitments and contingencies" for further discussion.
|
|
|
(3)
|
Net income (loss) includes gains on the revaluation of the 2017 Warrants of
$6.0 million
,
$122.3 million
,
$18.3 million
and
$12.6 million
during the first, second, third, and fourth quarters of 2017, respectively, primarily due to a decrease in EXCO's share price. See "Note 4. Derivative financial instruments" for further discussion.
|
|
|
16.
|
Supplemental information relating to oil and natural gas producing activities (unaudited)
|
The following supplemental information relating to our oil and natural gas producing activities for the
years ended December 31, 2018 and 2017
is presented in accordance with ASC 932,
Extractive Activities, Oil and Gas.
Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Amount
|
2018:
|
|
|
Proved property acquisition costs (1)
|
|
$
|
—
|
|
Unproved property acquisition costs (1)
|
|
—
|
|
Total property acquisition costs
|
|
—
|
|
Development
|
|
146,834
|
|
Exploration costs
|
|
—
|
|
Lease acquisitions and other
|
|
9,931
|
|
Capitalized asset retirement costs
|
|
—
|
|
Depletion per Boe
|
|
$
|
4.44
|
|
Depletion per Mcfe
|
|
$
|
0.74
|
|
2017:
|
|
|
Proved property acquisition costs
|
|
$
|
18,940
|
|
Unproved property acquisition costs
|
|
5,228
|
|
Total property acquisition costs
|
|
24,168
|
|
Development
|
|
128,323
|
|
Exploration costs (2)
|
|
19,538
|
|
Lease acquisitions and other
|
|
5,654
|
|
Capitalized asset retirement costs
|
|
12
|
|
Depletion per Boe
|
|
$
|
3.45
|
|
Depletion per Mcfe
|
|
$
|
0.57
|
|
|
|
(1)
|
The Appalachia JV Settlement resulted in the acquisition of
$33.5 million
and
$72.5 million
of unproved and proved oil and natural gas properties, respectively. Per the terms of the settlement agreement, the acquisition of interests in these oil and gas properties did not require us to transfer any cash consideration. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion of the Appalachia JV Settlement.
|
|
|
(2)
|
Exploration costs in 2017 related to the wells drilled in the Bossier shale in North Louisiana.
|
We retain independent engineering firms to prepare or audit annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls)
|
|
Natural
Gas
(Mmcf)
|
|
Mmcfe
|
December 31, 2016
|
|
10,168
|
|
|
415,719
|
|
|
476,727
|
|
Purchase of reserves in place (1)
|
|
—
|
|
|
50,456
|
|
|
50,456
|
|
Discoveries and extensions
|
|
13
|
|
|
21,880
|
|
|
21,958
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
Changes in price
|
|
679
|
|
|
30,200
|
|
|
34,274
|
|
Performance and other factors (2)
|
|
(290
|
)
|
|
72,332
|
|
|
70,593
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
|
(1,158
|
)
|
|
(80,136
|
)
|
|
(87,084
|
)
|
December 31, 2017
|
|
9,412
|
|
|
510,451
|
|
|
566,924
|
|
Purchase of reserves in place (3)
|
|
—
|
|
|
118,415
|
|
|
118,415
|
|
Discoveries and extensions
|
|
1,387
|
|
|
22,482
|
|
|
30,804
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
—
|
|
Changes in price
|
|
690
|
|
|
5,726
|
|
|
9,866
|
|
Performance and other factors (4)
|
|
3,170
|
|
|
22,486
|
|
|
41,502
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
|
(1,357
|
)
|
|
(98,779
|
)
|
|
(106,921
|
)
|
December 31, 2018
|
|
13,302
|
|
|
580,781
|
|
|
660,590
|
|
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls)
|
|
Natural
Gas
(Mmcf)
|
|
Mmcfe
|
Proved developed:
|
|
|
|
|
|
|
December 31, 2018
|
|
13,302
|
|
|
580,781
|
|
|
660,590
|
|
December 31, 2017
|
|
9,412
|
|
|
510,451
|
|
|
566,924
|
|
Proved undeveloped:
|
|
|
|
|
|
|
December 31, 2018
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(1)
|
Purchases of reserves in place during 2017 primarily related to the acquisition of incremental interests in certain oil and natural gas properties that we operate and undeveloped acreage in the North Louisiana region.
|
|
|
(2)
|
Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2017 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana region.
|
|
|
(3)
|
Purchases of reserves in place during 2018 related to the acquisition of incremental interests in the Appalachia JV Settlement on February 27, 2018. The Proved Reserves acquired in the Appalachia JV Settlement predominantly consists of proved producing properties in the Marcellus shale.
|
|
|
(4)
|
Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2018 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana and South Texas regions.
|
Standardized measure of discounted future net cash flows
We have summarized the Standardized Measure related to our proved oil and natural gas reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a
10%
discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Furthermore, the ability to demonstrate the financing available to fund a development program with Reasonable Certainty could have a significant impact on our Proved Undeveloped Reserves. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends.
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Year Ended December 31, 2018:
|
|
|
Future cash inflows
|
|
$
|
2,335,662
|
|
Future production costs
|
|
1,048,606
|
|
Future development costs (1)
|
|
65,033
|
|
Future income taxes (2)
|
|
—
|
|
Future net cash flows
|
|
1,222,023
|
|
Discount of future net cash flows at 10% per annum
|
|
464,654
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
757,369
|
|
Year Ended December 31, 2017:
|
|
|
|
Future cash inflows
|
|
$
|
1,690,056
|
|
Future production costs
|
|
863,847
|
|
Future development costs (1)
|
|
51,925
|
|
Future income taxes (2)
|
|
—
|
|
Future net cash flows
|
|
774,284
|
|
Discount of future net cash flows at 10% per annum
|
|
291,537
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
482,747
|
|
|
|
(1)
|
All of our Proved Undeveloped Reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reserves still existed at
December 31, 2018
and
2017
. As such, future development costs at
December 31, 2018
and
2017
consist primarily of estimated future plugging and abandonment costs.
|
|
|
(2)
|
Our tax basis in oil and natural gas properties exceeded the pre-tax cash inflows at December 31, 2018 and 2017. As a result, we are not expected to generate future taxable income from our oil and natural gas properties in the preparation of the Standardized Measure.
|
During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at
December 31, 2018
and
2017
used in the above table, were
$65.56
and
$51.34
per Bbl of oil, respectively, and
$3.10
and
$2.98
per Mmbtu of natural gas, respectively. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differentials. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma.
The following are the principal sources of change in the Standardized Measure:
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Year Ended December 31, 2018:
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(239,007
|
)
|
Net changes in prices and production costs
|
|
192,798
|
|
Extensions and discoveries, net of future development and production costs
|
|
70,394
|
|
Development costs during the period to the extent previously estimated
|
|
6,192
|
|
Changes in estimated future development costs
|
|
(6,314
|
)
|
Revisions of previous quantity estimates
|
|
136,700
|
|
Sales of reserves in place
|
|
—
|
|
Purchase of reserves in place
|
|
63,146
|
|
Accretion of discount
|
|
48,275
|
|
Changes in timing and other
|
|
2,438
|
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
274,622
|
|
Year Ended December 31, 2017:
|
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(99,260
|
)
|
Net changes in prices and production costs
|
|
91,998
|
|
Extensions and discoveries, net of future development and production costs
|
|
25,459
|
|
Development costs during the period to the extent previously estimated
|
|
1,913
|
|
Changes in estimated future development costs
|
|
(4,758
|
)
|
Revisions of previous quantity estimates
|
|
88,825
|
|
Sales of reserves in place
|
|
—
|
|
Purchase of reserves in place
|
|
40,991
|
|
Accretion of discount
|
|
31,093
|
|
Changes in timing and other
|
|
(4,444
|
)
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
171,817
|
|
Costs not subject to amortization
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. A significant portion of our acreage is held-by-production, which allows us to develop these properties within an optimum time frame.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Total
|
|
2018
|
|
2017
|
|
2016
|
|
2015 and
prior
|
Property acquisition costs
|
|
$
|
104,465
|
|
|
$
|
33,908
|
|
|
$
|
10,890
|
|
|
$
|
899
|
|
|
$
|
58,768
|
|
Exploration and development
|
|
13,900
|
|
|
13,900
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Capitalized interest
|
|
37,281
|
|
|
3,357
|
|
|
6,440
|
|
|
5,213
|
|
|
22,271
|
|
Total
|
|
$
|
155,646
|
|
|
$
|
51,165
|
|
|
$
|
17,330
|
|
|
$
|
6,112
|
|
|
$
|
81,039
|
|
Plan of Reorganization
On March 8, 2019, the Debtors filed the March 2019 Plan and related Disclosure Statement with the Court. See further discussion of the March 2019 Plan in “Note 1. Organization and basis of presentation”.
Chesapeake Settlement Agreement
On February 21, 2019, EXCO executed an agreement with CEC and CEML to settle litigation, claims against the Debtors and other matters ("Chesapeake Settlement Agreement"). Per the terms of the Chesapeake Settlement Agreement:
|
|
•
|
All claims filed by CEC and CEML in the Chapter 11 Cases shall be deemed disallowed and expunged. These claims primarily include costs related to the rejection of a marketing agreement in the North Louisiana region and pre-petition costs related to sales of natural gas in the South Texas region. As of December 31, 2018, our estimate of the allowable claims classified as "Liabilities subject to compromise" was
$8.6 million
for the rejection of the marketing agreement and
$2.0 million
pre-petition costs related to sales of natural gas;
|
|
|
•
|
EXCO agreed to release CEC and CEML from pre-petition litigation including the wrongful termination of a natural gas sales contract in South Texas and improper charges for post-production costs in North Louisiana. See further discussion of the litigation with CEC and CEML in "Item 3. Legal proceedings"; and
|
|
|
•
|
EXCO will assume certain sales contracts with CEML and joint operating agreements with CEC.
|
The Chesapeake Settlement Agreement will not be effective until it is approved by the Court. We filed a motion with the Court to approve the Chesapeake Settlement Agreement on February 25, 2019 and the hearing is scheduled for March 20, 2019.
Enterprise Settlement Agreement
On November 13, 2018, EXCO and Bluescape executed an agreement with Enterprise and Acadian to settle the litigation described in "Item 3. Legal proceedings" and claims against the Debtors ("EPD Settlement Agreement"). Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Per the terms of the EPD Settlement Agreement:
|
|
•
|
The proofs of claim filed by EPD in the Chapter 11 Cases shall be settled for an allowed general unsecured claim of
$10.0 million
. These claims primarily include costs related to the rejection of a natural gas sales agreement and natural gas transportation agreement in the North Louisiana region. On the effective date of a plan of reorganization, Bluescape shall be required to purchase the claim from EPD for
$5.0 million
;
|
|
|
•
|
The Debtors shall pay EPD: (i)
$6.25 million
on the effective date of a plan of reorganization, and (ii)
$6.25 million
on September 1, 2019; and
|
|
|
•
|
Upon completion of the payments from the Debtors and Bluescape to EPD, each party shall provide releases and take all actions to dismiss the aforementioned litigation.
|
The EPD Settlement Agreement will not be effective until it is approved by the Court. Furthermore, the EPD Settlement Agreement will be terminated if the effective date of a plan of reorganization does not occur prior to July 1, 2019. We filed a motion with the Court to approve the EPD Settlement Agreement on March 13, 2019 and the hearing is scheduled for April 11, 2019. As of December 31, 2018, our estimate of the allowable claims classified as "Liabilities subject to compromise" was
$298.5 million
for the rejection of the natural gas sales agreement with Enterprise and the natural gas transportation agreement with Acadian in the North Louisiana region.