NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.
Organization and basis of presentation
Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q 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.
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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 Condensed Consolidated Balance Sheets as of
September 30, 2018
and
December 31, 2017
, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three and
nine months ended September 30, 2018
and
2017
are for EXCO and its consolidated subsidiaries. The unaudited Condensed 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.
We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO as of
September 30, 2018
and its results of operations and cash flows for the periods presented. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO’s Annual Report on Form 10-K for the year ended
December 31, 2017
, filed with the SEC on
March 15, 2018
(“2017 Form 10-K”).
In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.
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 quarterly report on Form 10-Q 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 Condensed 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 Condensed 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 distribution 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:
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EXCO Resources Credit Agreement;
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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.
As of September 30, 2018
, we had
$156.4 million
in outstanding indebtedness and
$81.6 million
of available borrowing capacity under the DIP Facilities. See further discussion of the DIP Credit Agreement in “
Note 8. Debt
”. 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.
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:
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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;
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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;
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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;
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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
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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.
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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. The parties have engaged in settlement discussions related to this matter; however, there can be no assurance the parties will be able to reach an agreement. Any settlement reached between the parties would have to be approved by the Court. As of September 30, 2018, we have accrued
$27.6 million
related to the minimum volume commitment as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet.
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 “Plan”) and related Disclosure Statement with the Court. As is customary in bankruptcy proceedings, the Debtors subsequently filed amendments to the Plan and related Disclosure Statement with the Court. The Plan does not currently contemplate the divestiture of any of the Company’s assets. The restructuring transactions contemplated by the Plan include the following key elements:
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Holders of the DIP Credit Agreement will receive payment in full in cash with proceeds from a new revolving credit facility (“Exit Facility”);
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Holders of the 1.5 Lien Notes will receive payment in full in cash (without payment of any premium or “make-whole”) with the proceeds from a new second lien debt instrument;
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Holders of the 1.75 Lien Term Loans will receive
82 percent
of the equity in the reorganized Company and
82 percent
of the interests in a claims trust that will hold certain litigation claims (“Claims Trust”);
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Holders of the Second Lien Term Loans, 2018 Notes, 2022 Notes and allowed general unsecured claims (other than “Convenience Claims” as defined below or those creditors that elect to be treated as holding Convenience Claims, and claims against Raider Marketing, LP or Raider Marketing GP, LLC) will receive, collectively, (i)
18 percent
of
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the equity in the reorganized Company, (ii)
$15.4 million
in cash, and (iii)
18 percent
of the interests in the Claims Trust;
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Holders of allowed claims greater than
$0
but less than or equal to
$405,000
(“Convenience Claims”), along with any holder of an allowed general unsecured claim who elects to be treated as a holder of an allowed Convenience Claim, will receive a pro rata share of
$5.0 million
in cash;
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Holders of claims against Raider Marketing, LP or Raider Marketing GP, LLC shall not receive a distribution and claims will be deemed canceled, discharged, released and extinguished;
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Holders of existing equity interests in EXCO shall not receive a distribution and the equity interests will be deemed cancelled, discharged, released and extinguished; and
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The carriers of directors’ and officers’ liability insurance coverage related to the Debtors agreed to pay
$13.4 million
(“D&O Proceeds”) in exchange for full and final settlement of potential claims and causes of action against current and former directors and officers.
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The Debtors shall fund distributions under the Plan with: (i) cash on hand; (ii) the Exit Facility; (iii) a new second lien debt instrument; (iv) the equity in the reorganized Company; and, (v) the D&O Proceeds.
We currently believe the Plan would allow us to preserve our tax attributes upon emergence if we are eligible for an exception in Section 382(l)(5) of the Internal Revenue Code. See further discussion of Section 382 of the Internal Revenue Code and the impact of the Plan on our tax attributes in “Note 10. Income taxes”.
On November 5, 2018, the Court authorized us to solicit acceptances of the Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the Plan. We are currently in the process of soliciting votes with respect to the Plan. The Plan is subject to acceptance by certain holders of claims against the Debtors and to confirmation by the Court. The Plan will be accepted by a class of claims entitled to vote if at least one-half in number and two-thirds in dollar amount of claims actually voting in the class have voted to accept the Plan. Under certain circumstances set forth in the Bankruptcy Code, the Court may confirm the Plan even if it has not been accepted by all impaired classes of claims and equity interests if the Debtors demonstrate, among other things, that (i) no class junior to the rejecting class is receiving or retaining property under the plan and (ii) no class of claims or interests senior to the rejecting class is being paid more than in full. A hearing to consider confirmation of the Plan is scheduled to be held on December 10, 2018 in the Court (“Confirmation Hearing”). If the Plan is ultimately confirmed by the Court, the Debtors will emerge from bankruptcy pursuant to the terms of the Plan.
Accounting during bankruptcy
We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852,
Reorganizations
(“ASC 852”), in the preparation of these Condensed 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 Condensed Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Condensed Consolidated Balance Sheet as of
September 30, 2018
as “Liabilities subject to compromise.”
Liabilities subject to compromise
The accompanying Condensed Consolidated Balance Sheet as of
September 30, 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 Condensed Consolidated Balance Sheet as of
September 30, 2018
:
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(in thousands)
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September 30, 2018
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Current maturities of long-term debt
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$
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927,917
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Accrued interest payable
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34,281
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Accounts payable, accrued expenses and other liabilities
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110,656
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Liabilities related to rejected executory contracts
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418,771
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Liabilities subject to compromise
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$
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1,491,625
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As of
September 30, 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 Condensed Consolidated Statement of Operations for
the three and nine months ended September 30, 2018
:
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(in thousands)
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Three Months Ended September 30, 2018
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Nine Months Ended September 30, 2018
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Legal and professional fees
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$
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15,184
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$
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44,766
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Deferred financing costs, debt discounts and deferred reductions in carrying value
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—
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30,509
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Rejection of executory contracts
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2,985
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312,182
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Reorganization items, net
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$
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18,169
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$
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387,457
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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 Condensed Consolidated Statement of Operations was approximately
$75.6 million
, representing interest expense from the Petition Date through
September 30, 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. These policies and others are summarized in our
2017
Form 10-K. 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
”.
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 leases. 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 currently assessing the potential impact of ASU 2016-02 and related clarifying updates and expect they will have an impact on our consolidated financial condition and results of operations upon adoption. We are currently unable to quantify the impact the standard will have on our consolidated financial condition and results of operations.
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
$12.2 million
for the
nine months ended September 30, 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 7. 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. As described in the 2017 Form 10-K, 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 are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. 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.
Revenue from Contracts with Customers (Topic 606)
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 2014-09 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. Historically, these differences have been immaterial. Natural gas imbalances at September 30, 2018 and 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 three and nine months ended September 30, 2018
, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
3.
Acquisitions, divestitures and other significant events
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. Under the terms of the Appalachia JV Settlement:
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•
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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;
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•
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Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV;
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•
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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
;
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•
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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
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•
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EXCO caused the arbitration and the state court action to be dismissed with prejudice.
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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.
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(in thousands)
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|
Amount
|
|
Assets acquired:
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|
Cash and cash equivalents
|
|
$
|
14,832
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|
|
Accounts receivable, net
|
|
6,493
|
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|
Other current assets
|
|
5,264
|
|
|
Unproved oil and natural gas properties
|
|
33,542
|
|
|
Proved developed and undeveloped oil and natural gas properties, net
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72,548
|
|
|
Other assets
|
|
18,109
|
|
|
Liabilities assumed:
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|
|
|
Accounts payable and accrued liabilities
|
|
(9,718
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)
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|
Asset retirement obligations
|
|
(2,315
|
)
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|
Other long-term liabilities
|
|
(9,895
|
)
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|
Fair value of net assets acquired
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|
$
|
128,860
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|
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:
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Three Months Ended September 30,
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Nine Months Ended September 30,
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(in thousands except for per share data)
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2018
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2017
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2018
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|
2017
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|
Oil and natural gas revenues
|
$
|
98,571
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|
|
$
|
67,556
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|
$
|
291,244
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|
$
|
228,638
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|
Net income (loss) (1)
|
3,684
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|
(19,295
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)
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|
(198,361
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)
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|
113,547
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Basic earnings (loss) per share
|
$
|
0.17
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|
$
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(0.83
|
)
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|
$
|
(9.14
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)
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|
$
|
5.51
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|
Diluted earnings (loss) per share
|
$
|
0.17
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|
|
$
|
(0.83
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)
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|
$
|
(9.14
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)
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|
$
|
5.51
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|
|
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|
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(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 three and
nine months ended September 30, 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.
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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 had received
$1.7 million
under these agreements during 2018.
4.
Asset retirement obligations
The following is a reconciliation of our asset retirement obligations for the
nine months ended September 30, 2018
:
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(in thousands)
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Asset retirement obligations at beginning of period
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|
$
|
12,017
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Activity during the period:
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Liabilities incurred during the period
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—
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Revisions in estimated assumptions
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(1
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)
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Liabilities settled during the period
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|
(77
|
)
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|
Adjustment to liability due to acquisitions (1)
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2,319
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|
|
Adjustment to liability due to divestitures
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|
(7
|
)
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Accretion of discount
|
|
778
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|
|
Asset retirement obligations at end of period
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|
15,029
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|
Less current portion
|
|
600
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|
|
Long-term portion
|
|
$
|
14,429
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(1)
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The increase in our asset retirement obligations during the
nine months ended September 30, 2018
is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement.
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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.
5.
Oil and natural gas properties
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”). 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 extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were
no
impairments of unproved properties during
the three and nine months ended September 30, 2018
and 2017.
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 an 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, 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. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts has positively impacted the present value of our proved reserves. See further discussion of the rejection of executory contracts in “Note 1. Organization and basis of presentation”.
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.
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Average spot prices
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Oil (per Bbl)
|
|
Natural gas (per Mmbtu)
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|
September 30, 2018
|
|
$
|
63.54
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|
|
$
|
2.91
|
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|
June 30, 2018
|
|
57.68
|
|
|
2.92
|
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|
March 31, 2018
|
|
53.49
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|
|
3.00
|
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|
December 31, 2017
|
|
51.34
|
|
|
2.98
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We did
no
t recognize an impairment to our proved oil and natural gas properties for
the three and nine months ended September 30, 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
September 30, 2018
, our proved undeveloped reserves were limited to certain wells expected to be completed during 2018. 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.
6.
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 three and nine months ended September 30, 2018
and
2017
:
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Three Months Ended September 30,
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|
Nine Months Ended September 30,
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(in thousands, except per share data)
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|
2018
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|
2017
|
|
2018
|
|
2017
|
|
Basic net income (loss) per common share:
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|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,684
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|
|
$
|
(18,824
|
)
|
|
$
|
(199,621
|
)
|
|
$
|
110,119
|
|
|
Weighted average common shares outstanding
|
|
21,616
|
|
|
23,319
|
|
|
21,710
|
|
|
20,599
|
|
|
Net income (loss) per basic common share
|
|
$
|
0.17
|
|
|
$
|
(0.81
|
)
|
|
$
|
(9.19
|
)
|
|
$
|
5.35
|
|
|
Diluted net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,684
|
|
|
$
|
(18,824
|
)
|
|
$
|
(199,621
|
)
|
|
$
|
110,119
|
|
|
Weighted average common shares outstanding
|
|
21,616
|
|
|
23,319
|
|
|
21,710
|
|
|
20,599
|
|
|
Dilutive effect of:
|
|
|
|
|
|
|
|
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|
Restricted shares and restricted share units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Weighted average common shares and common share equivalents outstanding
|
|
21,616
|
|
|
23,319
|
|
|
21,710
|
|
|
20,599
|
|
|
Net income (loss) per diluted common share
|
|
$
|
0.17
|
|
|
$
|
(0.81
|
)
|
|
$
|
(9.19
|
)
|
|
$
|
5.35
|
|
Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, warrants representing 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.
Diluted net income (loss) per common share for
the three and nine months ended September 30, 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, warrants representing the right to purchase our common shares at an exercise price of
$13.95
, and for
the three and nine months ended September 30, 2017
, warrants issued to Energy Strategic Advisory Services LLC (“ESAS”), whether exercisable or not. The computation of diluted net income (loss) per share excluded
10,792,583
and
21,723,733
antidilutive share equivalents for the
three months ended September 30, 2018
and
2017
, respectively, and
11,414,989
and
9,951,298
antidilutive common share equivalents for the
nine months ended September 30, 2018
and
2017
, respectively. The antidilutive common share equivalents for
the three and nine months ended September 30, 2018
and 2017 primarily related to the warrants representing the right to purchase our common shares at an exercise price of
$13.95
.
7.
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 Condensed Consolidated Balance Sheets:
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|
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|
(in thousands)
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
Current assets
|
|
Derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
1,150
|
|
|
Liabilities subject to compromise
|
|
Derivative financial instruments - common share warrants
|
|
(522
|
)
|
|
—
|
|
|
Long-term liabilities
|
|
Derivative financial instruments - common share warrants
|
|
—
|
|
|
(1,950
|
)
|
The table below presents the effect of derivative financial instruments on our Condensed Consolidated Statements of Operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(in thousands)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
Gain (loss) on derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
860
|
|
|
$
|
(615
|
)
|
|
$
|
22,934
|
|
|
Gain (loss) on derivative financial instruments - common share warrants
|
|
(287
|
)
|
|
18,286
|
|
|
1,428
|
|
|
146,585
|
|
Commodity derivative financial instruments
We have historically entered into commodity derivative financial instruments 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. 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 Condensed Consolidated Balance Sheets fair value amounts.
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
September 30, 2018
, we did not have any outstanding commodity derivative financial instruments.
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”).
On January 16, 2018, affiliates of Fairfax, which had previously been identified as a related party, surrendered all of their rights to the Commitment Fee, Amendment Fee and Financing Warrants. Their rights under the 2017 Warrants 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.
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 5 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. The 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 a loss of
$0.3 million
and a gain
$18.3 million
during the
three months ended September 30, 2018 and 2017
, respectively, and gains of
$1.4 million
and
$146.6 million
during the
nine months ended September 30, 2018
and
2017
, respectively, on the revaluation of the warrants, in “
Gain (loss) on derivative financial instruments - common share warrants
” on the Condensed 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.
8.
Debt
The carrying value of our total debt is summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
September 30, 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 are 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 Condensed Consolidated Statement of Operations for the
nine months ended September 30, 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 Condensed Consolidated Statement of Operations for the
nine months ended September 30, 2018
.
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. 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 have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of September 30, 2018. As of September 30, 2018, the carrying value for each of our debt instruments approximates the principal amount. As of September 30, 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 estimate of the recoverability of claims related to these debt instruments.
The Plan provides for a reorganization of the Debtors as a going concern with a significant reduction in indebtedness and improved capital structure. See further discussion of the key proposed restructuring elements contemplated in the Plan and the confirmation process in “Note 1. Organization and basis of presentation”. The DIP Credit Agreement is expected to be repaid in full with proceeds from the issuance of the Exit Facility. Furthermore, the 1.5 Lien Notes are expected to be repaid in full in cash (without payment of any premium or “make-whole”) with the proceeds from a new second lien debt instrument. We are currently engaged in discussions with financial institutions regarding the potential issuance of the Exit Facility and a new second lien debt instrument. Our ability to consummate the Plan is dependent upon our ability to issue the Exit Facility and the new second lien debt instrument. There can be no assurance the exit financing required to consummate the Plan will be available or, if available, offered on acceptable terms.
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
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 may 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 September 30, 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
September 30, 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 DIP Facilities will mature on the earliest of (a)
12
months from the initial borrowings on January 22, 2018, (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. The DIP Credit Agreement provided us with an option to extend the maturity of the DIP Facilities to the date that is
18
months from the initial borrowing date if certain conditions are met. These conditions included a requirement to file a plan of reorganization with the Court no later than July 1, 2018. We did not file a plan of reorganization with the Court prior to July 1, 2018; therefore, an extension of the DIP Facilities beyond the original maturity date would require a waiver or consent from the DIP Lenders. Borrowings under the DIP Credit Agreement are subject to an initial borrowing base of
$250.0 million
. The initial borrowing base redetermination will occur on or about January 1, 2019. Thereafter, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year 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 September 30, 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.
9.
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
nine months ended September 30, 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
September 30, 2018
and
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2018
|
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - common share warrants
|
|
$
|
—
|
|
|
$
|
522
|
|
|
$
|
—
|
|
|
$
|
522
|
|
|
|
|
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 Condensed 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 7. 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 8. Debt
” for the carrying value and the principal balance of each debt instrument included in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2018
|
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
1.5 Lien Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
315,790
|
|
|
$
|
315,790
|
|
|
1.75 Lien Term Loans
|
|
—
|
|
|
—
|
|
|
322,561
|
|
|
322,561
|
|
|
Second Lien Term Loans
|
|
—
|
|
|
—
|
|
|
5,260
|
|
|
5,260
|
|
|
2018 Notes
|
|
20,394
|
|
|
—
|
|
|
—
|
|
|
20,394
|
|
|
2022 Notes
|
|
10,876
|
|
|
—
|
|
|
—
|
|
|
10,876
|
|
|
|
|
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
|
|
10.
Income taxes
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our annual effective tax rate is highly sensitive to estimates of ordinary income or loss primarily due to significant permanent differences related to the non-taxable gains or losses on the 2017 Warrants and non-deductible interest on our 1.5 Lien Notes and 1.75 Lien Term Loans.
We have accumulated financial net deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances
increased
$37.4 million
for the
nine months ended September 30, 2018
. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately
$880.9 million
that have fully offset our net deferred tax assets as of
September 30, 2018
. The valuation allowances will continue to be recognized until the realization of future deferred tax
benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.
The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change pursuant to 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 restrictions imposed by the Court on the trading of our equity securities to protect our use of NOLs in “
Note 1. Organization and basis of presentation
”. 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. As of September 30, 2018, we had estimated NOLs of
$2.3 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 percent 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.
We currently believe the structure of the Plan would allow us to qualify for the 382(l)(5) Exception. 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, our ability to qualify for the 382(l)(5) Exception is subject to further analysis and depends on our ability to consummate the Plan in substantially the same form as currently set forth, the actions of our creditors and the board of directors of the reorganized Company. Therefore, we cannot provide any assurance regarding the extent of limitations on the Company’s tax attributes upon emergence from bankruptcy.
On December 22, 2017, the United States enacted the 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. We have credits that are expected to be refunded between 2018 and 2020 as a result of the Tax Act and monetization opportunities under current law in 2017. 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. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. 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.
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 nine months ended September 30, 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill.
11.
Condensed consolidating financial statements
As of
September 30, 2018
, the majority of EXCO’s subsidiaries were guarantors under the DIP Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit agreements governing the 1.75 Lien Term Loans and 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, Second 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
(Unaudited)
As of September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
53,191
|
|
|
$
|
(9,960
|
)
|
|
$
|
23,732
|
|
|
$
|
—
|
|
|
$
|
66,963
|
|
|
Restricted cash
|
|
653
|
|
|
6,375
|
|
|
—
|
|
|
—
|
|
|
7,028
|
|
|
Other current assets
|
|
8,100
|
|
|
106,892
|
|
|
5,513
|
|
|
—
|
|
|
120,505
|
|
|
Total current assets
|
|
61,944
|
|
|
103,307
|
|
|
29,245
|
|
|
—
|
|
|
194,496
|
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
4,736
|
|
|
—
|
|
|
4,736
|
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
114,920
|
|
|
33,542
|
|
|
—
|
|
|
148,462
|
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
334,688
|
|
|
2,899,762
|
|
|
72,881
|
|
|
—
|
|
|
3,307,331
|
|
|
Accumulated depletion
|
|
(330,776
|
)
|
|
(2,477,099
|
)
|
|
(4,299
|
)
|
|
—
|
|
|
(2,812,174
|
)
|
|
Oil and natural gas properties, net
|
|
3,912
|
|
|
537,583
|
|
|
102,124
|
|
|
—
|
|
|
643,619
|
|
|
Other property and equipment, net and other non-current assets
|
|
909
|
|
|
20,090
|
|
|
17,565
|
|
|
—
|
|
|
38,564
|
|
|
Investments in and (advances to) affiliates, net
|
|
338,948
|
|
|
—
|
|
|
—
|
|
|
(338,948
|
)
|
|
—
|
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
|
Total assets
|
|
$
|
419,006
|
|
|
$
|
810,842
|
|
|
$
|
153,670
|
|
|
$
|
(338,948
|
)
|
|
$
|
1,044,570
|
|
|
Liabilities and shareholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
473,364
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
473,364
|
|
|
Other current liabilities
|
|
22,534
|
|
|
70,016
|
|
|
6,341
|
|
|
—
|
|
|
98,891
|
|
|
Other long-term liabilities
|
|
—
|
|
|
14,615
|
|
|
10,125
|
|
|
—
|
|
|
24,740
|
|
|
Liabilities subject to compromise
|
|
967,158
|
|
|
524,467
|
|
|
—
|
|
|
—
|
|
|
1,491,625
|
|
|
Payable to parent
|
|
—
|
|
|
2,443,442
|
|
|
3,546
|
|
|
(2,446,988
|
)
|
|
—
|
|
|
Total shareholders’ equity
|
|
(1,044,050
|
)
|
|
(2,241,698
|
)
|
|
133,658
|
|
|
2,108,040
|
|
|
(1,044,050
|
)
|
|
Total liabilities and shareholders’ equity
|
|
$
|
419,006
|
|
|
$
|
810,842
|
|
|
$
|
153,670
|
|
|
$
|
(338,948
|
)
|
|
$
|
1,044,570
|
|
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
(Unaudited)
For the Three Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
87,761
|
|
|
$
|
5,779
|
|
|
$
|
—
|
|
|
$
|
93,540
|
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
4,946
|
|
|
85
|
|
|
—
|
|
|
5,031
|
|
|
Total revenues
|
|
—
|
|
|
92,707
|
|
|
5,864
|
|
|
—
|
|
|
98,571
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
16,585
|
|
|
731
|
|
|
—
|
|
|
17,316
|
|
|
Gathering and transportation
|
|
—
|
|
|
18,258
|
|
|
955
|
|
|
—
|
|
|
19,213
|
|
|
Purchased natural gas
|
|
—
|
|
|
3,776
|
|
|
—
|
|
|
—
|
|
|
3,776
|
|
|
Depletion, depreciation and amortization
|
|
75
|
|
|
18,533
|
|
|
2,005
|
|
|
—
|
|
|
20,613
|
|
|
Accretion of liabilities
|
|
—
|
|
|
234
|
|
|
318
|
|
|
—
|
|
|
552
|
|
|
General and administrative
|
|
(9,647
|
)
|
|
14,448
|
|
|
1,314
|
|
|
—
|
|
|
6,115
|
|
|
Loss on Appalachia JV Settlement
|
|
—
|
|
|
—
|
|
|
240
|
|
|
—
|
|
|
240
|
|
|
Other operating items
|
|
—
|
|
|
(495
|
)
|
|
120
|
|
|
—
|
|
|
(375
|
)
|
|
Total costs and expenses
|
|
(9,572
|
)
|
|
71,339
|
|
|
5,683
|
|
|
—
|
|
|
67,450
|
|
|
Operating income
|
|
9,572
|
|
|
21,368
|
|
|
181
|
|
|
—
|
|
|
31,121
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(8,993
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,993
|
)
|
|
Loss on derivative financial instruments - common share warrants
|
|
(287
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(287
|
)
|
|
Other income
|
|
4
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
Reorganization items, net
|
|
(18,169
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18,169
|
)
|
|
Net income from consolidated subsidiaries
|
|
21,557
|
|
|
—
|
|
|
—
|
|
|
(21,557
|
)
|
|
—
|
|
|
Total other income (expense)
|
|
(5,888
|
)
|
|
8
|
|
|
—
|
|
|
(21,557
|
)
|
|
(27,437
|
)
|
|
Income before income taxes
|
|
3,684
|
|
|
21,376
|
|
|
181
|
|
|
(21,557
|
)
|
|
3,684
|
|
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net income
|
|
$
|
3,684
|
|
|
$
|
21,376
|
|
|
$
|
181
|
|
|
$
|
(21,557
|
)
|
|
$
|
3,684
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Three Months Ended September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
61,229
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
61,229
|
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
5,507
|
|
|
—
|
|
|
—
|
|
|
5,507
|
|
|
Total revenues
|
|
—
|
|
|
66,736
|
|
|
—
|
|
|
—
|
|
|
66,736
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
12,259
|
|
|
—
|
|
|
—
|
|
|
12,259
|
|
|
Gathering and transportation
|
|
—
|
|
|
28,743
|
|
|
—
|
|
|
—
|
|
|
28,743
|
|
|
Purchased natural gas
|
|
—
|
|
|
5,388
|
|
|
—
|
|
|
—
|
|
|
5,388
|
|
|
Depletion, depreciation and amortization
|
|
88
|
|
|
13,430
|
|
|
—
|
|
|
—
|
|
|
13,518
|
|
|
Accretion of liabilities
|
|
—
|
|
|
221
|
|
|
—
|
|
|
—
|
|
|
221
|
|
|
General and administrative
|
|
(5,042
|
)
|
|
15,077
|
|
|
—
|
|
|
—
|
|
|
10,035
|
|
|
Other operating items
|
|
—
|
|
|
1,714
|
|
|
—
|
|
|
—
|
|
|
1,714
|
|
|
Total costs and expenses
|
|
(4,954
|
)
|
|
76,832
|
|
|
—
|
|
|
—
|
|
|
71,878
|
|
|
Operating income (loss)
|
|
4,954
|
|
|
(10,096
|
)
|
|
—
|
|
|
—
|
|
|
(5,142
|
)
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(32,888
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(32,888
|
)
|
|
Gain on derivative financial instruments - commodity derivatives
|
|
860
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
860
|
|
|
Gain on derivative financial instruments - common share warrants
|
|
18,286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,286
|
|
|
Other income
|
|
13
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
Equity income
|
|
—
|
|
|
—
|
|
|
354
|
|
|
—
|
|
|
354
|
|
|
Net loss from consolidated subsidiaries
|
|
(9,730
|
)
|
|
—
|
|
|
—
|
|
|
9,730
|
|
|
—
|
|
|
Total other income (expense)
|
|
(23,459
|
)
|
|
12
|
|
|
354
|
|
|
9,730
|
|
|
(13,363
|
)
|
|
Income (loss) before income taxes
|
|
(18,505
|
)
|
|
(10,084
|
)
|
|
354
|
|
|
9,730
|
|
|
(18,505
|
)
|
|
Income tax expense
|
|
319
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
319
|
|
|
Net income (loss)
|
|
$
|
(18,824
|
)
|
|
$
|
(10,084
|
)
|
|
$
|
354
|
|
|
$
|
9,730
|
|
|
$
|
(18,824
|
)
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Nine Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
258,809
|
|
|
$
|
12,653
|
|
|
$
|
—
|
|
|
$
|
271,462
|
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
15,477
|
|
|
226
|
|
|
—
|
|
|
15,703
|
|
|
Total revenues
|
|
—
|
|
|
274,286
|
|
|
12,879
|
|
|
—
|
|
|
287,165
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
42,103
|
|
|
2,072
|
|
|
—
|
|
|
44,175
|
|
|
Gathering and transportation
|
|
—
|
|
|
58,164
|
|
|
2,335
|
|
|
—
|
|
|
60,499
|
|
|
Purchased natural gas
|
|
—
|
|
|
11,634
|
|
|
—
|
|
|
—
|
|
|
11,634
|
|
|
Depletion, depreciation and amortization
|
|
232
|
|
|
55,854
|
|
|
4,733
|
|
|
—
|
|
|
60,819
|
|
|
Accretion of liabilities
|
|
—
|
|
|
693
|
|
|
762
|
|
|
—
|
|
|
1,455
|
|
|
General and administrative
|
|
(25,970
|
)
|
|
43,831
|
|
|
3,084
|
|
|
—
|
|
|
20,945
|
|
|
Gain on Appalachia JV Settlement
|
|
—
|
|
|
—
|
|
|
(119,237
|
)
|
|
—
|
|
|
(119,237
|
)
|
|
Other operating items
|
|
(35
|
)
|
|
(1,181
|
)
|
|
(166
|
)
|
|
—
|
|
|
(1,382
|
)
|
|
Total costs and expenses
|
|
(25,773
|
)
|
|
211,098
|
|
|
(106,417
|
)
|
|
—
|
|
|
78,908
|
|
|
Operating income
|
|
25,773
|
|
|
63,188
|
|
|
119,296
|
|
|
—
|
|
|
208,257
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(25,981
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25,981
|
)
|
|
Loss on derivative financial instruments - commodity derivatives
|
|
(615
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(615
|
)
|
|
Gain on derivative financial instruments - common share warrants
|
|
1,428
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,428
|
|
|
Other income
|
|
25
|
|
|
23
|
|
|
2
|
|
|
—
|
|
|
50
|
|
|
Equity income
|
|
—
|
|
|
—
|
|
|
179
|
|
|
—
|
|
|
179
|
|
|
Reorganization items, net
|
|
(78,260
|
)
|
|
(309,197
|
)
|
|
—
|
|
|
—
|
|
|
(387,457
|
)
|
|
Net loss from consolidated subsidiaries
|
|
(126,509
|
)
|
|
—
|
|
|
—
|
|
|
126,509
|
|
|
—
|
|
|
Total other income (expense)
|
|
(229,912
|
)
|
|
(309,174
|
)
|
|
181
|
|
|
126,509
|
|
|
(412,396
|
)
|
|
Income (loss) before income taxes
|
|
(204,139
|
)
|
|
(245,986
|
)
|
|
119,477
|
|
|
126,509
|
|
|
(204,139
|
)
|
|
Income tax benefit
|
|
(4,518
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,518
|
)
|
|
Net income (loss)
|
|
$
|
(199,621
|
)
|
|
$
|
(245,986
|
)
|
|
$
|
119,477
|
|
|
$
|
126,509
|
|
|
$
|
(199,621
|
)
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Unaudited)
For the Nine Months Ended September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
195,072
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
195,072
|
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
19,208
|
|
|
—
|
|
|
—
|
|
|
19,208
|
|
|
Total revenues
|
|
—
|
|
|
214,280
|
|
|
—
|
|
|
—
|
|
|
214,280
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
35,822
|
|
|
—
|
|
|
—
|
|
|
35,822
|
|
|
Gathering and transportation
|
|
—
|
|
|
83,183
|
|
|
—
|
|
|
—
|
|
|
83,183
|
|
|
Purchased natural gas
|
|
—
|
|
|
18,193
|
|
|
—
|
|
|
—
|
|
|
18,193
|
|
|
Depletion, depreciation and amortization
|
|
224
|
|
|
36,424
|
|
|
—
|
|
|
—
|
|
|
36,648
|
|
|
Accretion of liabilities
|
|
—
|
|
|
648
|
|
|
—
|
|
|
—
|
|
|
648
|
|
|
General and administrative
|
|
(32,169
|
)
|
|
45,225
|
|
|
—
|
|
|
—
|
|
|
13,056
|
|
|
Other operating items
|
|
577
|
|
|
2,492
|
|
|
—
|
|
|
—
|
|
|
3,069
|
|
|
Total costs and expenses
|
|
(31,368
|
)
|
|
221,987
|
|
|
—
|
|
|
—
|
|
|
190,619
|
|
|
Operating income
|
|
31,368
|
|
|
(7,707
|
)
|
|
—
|
|
|
—
|
|
|
23,661
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(75,318
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(75,320
|
)
|
|
Gain on derivative financial instruments - commodity derivatives
|
|
22,934
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,934
|
|
|
Gain on derivative financial instruments - common share warrants
|
|
146,585
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
146,585
|
|
|
Loss on restructuring of debt
|
|
(6,380
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,380
|
)
|
|
Other income (expense)
|
|
14
|
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
4
|
|
|
Equity income
|
|
—
|
|
|
—
|
|
|
1,009
|
|
|
—
|
|
|
1,009
|
|
|
Net loss from consolidated subsidiaries
|
|
(6,710
|
)
|
|
—
|
|
|
—
|
|
|
6,710
|
|
|
—
|
|
|
Total other income (expense)
|
|
81,125
|
|
|
(12
|
)
|
|
1,009
|
|
|
6,710
|
|
|
88,832
|
|
|
Income (loss) before income taxes
|
|
112,493
|
|
|
(7,719
|
)
|
|
1,009
|
|
|
6,710
|
|
|
112,493
|
|
|
Income tax expense
|
|
2,374
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,374
|
|
|
Net income (loss)
|
|
$
|
110,119
|
|
|
$
|
(7,719
|
)
|
|
$
|
1,009
|
|
|
$
|
6,710
|
|
|
$
|
110,119
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the Nine Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(18,946
|
)
|
|
$
|
122,746
|
|
|
$
|
5,736
|
|
|
$
|
—
|
|
|
$
|
109,536
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(921
|
)
|
|
(128,835
|
)
|
|
14,450
|
|
|
—
|
|
|
(115,306
|
)
|
|
Other
|
|
—
|
|
|
950
|
|
|
—
|
|
|
—
|
|
|
950
|
|
|
Advances/investments with affiliates
|
|
598
|
|
|
(4,144
|
)
|
|
3,546
|
|
|
—
|
|
|
—
|
|
|
Net cash provided by (used in) investing activities
|
|
(323
|
)
|
|
(132,029
|
)
|
|
17,996
|
|
|
—
|
|
|
(114,356
|
)
|
|
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 (decrea
se) in cash, cash equivalents and restricted cash
|
|
4,674
|
|
|
(9,283
|
)
|
|
23,732
|
|
|
—
|
|
|
19,123
|
|
|
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
|
|
$
|
53,844
|
|
|
$
|
(3,585
|
)
|
|
$
|
23,732
|
|
|
$
|
—
|
|
|
$
|
73,991
|
|
EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Unaudited)
For the Nine Months Ended September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(9,637
|
)
|
|
$
|
60,744
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
51,107
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(1,011
|
)
|
|
(114,663
|
)
|
|
—
|
|
|
—
|
|
|
(115,674
|
)
|
|
Proceeds from disposition of property and equipment
|
|
—
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
Net changes in amounts due to joint ventures
|
|
—
|
|
|
(9,498
|
)
|
|
—
|
|
|
—
|
|
|
(9,498
|
)
|
|
Advances/investments with affiliates
|
|
(79,406
|
)
|
|
79,406
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net cash used in investing activities
|
|
(80,417
|
)
|
|
(44,730
|
)
|
|
—
|
|
|
—
|
|
|
(125,147
|
)
|
|
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
|
)
|
|
Debt financing costs and other
|
|
(22,077
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,077
|
)
|
|
Net cash provided by financing activities
|
|
159,660
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
159,660
|
|
|
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
69,606
|
|
|
16,014
|
|
|
—
|
|
|
—
|
|
|
85,620
|
|
|
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
|
|
$
|
94,216
|
|
|
$
|
11,622
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
105,838
|
|
12.
Subsequent events
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. 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. Upon payment in full of these amounts, 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;
|
|
|
|
|
•
|
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 September 30, 2018, 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. See further discussion regarding this dispute with Shell Energy in the 2017 Form 10-K and other periodic filings with the SEC.