NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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1.
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Organization and basis of presentation
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Unless the context requires otherwise, references in this Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” 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. We are currently evaluating the potential divestiture of our properties in South Texas; however, no assurance can be given as to outcome or timing of such transaction.
•
Appalachia
The Appalachia region is primarily comprised of Marcellus shale assets following the divestitures of substantially all of our shallow conventional assets during 2016. We have a joint venture with Shell covering our Marcellus shale assets in the Appalachia region ("Appalachia JV"). EXCO and Shell each own 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 a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a
50%
interest in OPCO.
The accompanying Consolidated Balance Sheets as of
December 31, 2016
and
2015
, Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended
December 31, 2016
,
2015
and
2014
are for EXCO and its subsidiaries. The consolidated financial statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.
Going Concern Assessment and Management’s Plans
These Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. We define liquidity as cash and restricted cash plus the unused borrowing base under our credit agreement ("Liquidity"). As of
December 31, 2016
, the Company had
$9.1 million
in cash and cash equivalents,
$46.2 million
of availability under its credit agreement ("EXCO Resources Credit Agreement") and a working capital deficit of
$147.7 million
.
On
March 15, 2017
, we closed a series of transactions intended to improve our Liquidity and capital structure. This included the issuance of
$300.0 million
in aggregate principal amount of senior secured 1.5 lien notes due
March 20, 2022
("1.5 Lien Notes") and the exchange of
$682.8 million
in aggregate principal amount of our senior secured second lien term loans due October 26, 2020 ("Second Lien Term Loans") for a like amount of senior 1.75 lien term loans due October 26, 2020 ("1.75 Lien Term Loans"). The 1.5 Lien Notes and 1.75 Lien Term Loans provide us the option to pay interest in cash or, subject to certain limitations, common shares or additional indebtedness ("PIK Payments"). The proceeds from the issuance of the 1.5 Lien Notes were primarily utilized to repay the outstanding indebtedness under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement was amended to reduce the borrowing base to
$150.0 million
, permit the issuance of the
1.5 Lien Notes and the exchanges of Second Lien Term Loans, and modify certain financial covenants. See further discussion of these transactions as part of "Note 18. Subsequent Events".
The payment of interest in common shares on the 1.5 Lien Notes and 1.75 Lien Term Loans would improve our Liquidity and future cash flows. Our ability to pay interest in common shares is restricted until the shareholder approval is obtained to permit the issuance of common shares in connection with the transactions. The amount of PIK Payments made in additional 1.5 Lien Notes or 1.75 Lien Term Loans is subject to incurrence covenants within our debt agreements that limit our aggregate secured indebtedness to
$1.2 billion
. If we do not receive the shareholder vote to approve the issuance of common shares in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans, then we may be required to pay interest in cash that would further restrict our Liquidity and ability to comply with debt covenants. Furthermore, if the shareholder approval is not obtained by
September 30, 2017
, subject to certain extensions, the interest rate for cash and PIK Payments on the 1.5 Lien Notes will significantly increase.
The modified covenants in the EXCO Resources Credit Agreement include a requirement for our ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") to exceed a minimum of
1.75
to 1.0 for the fiscal quarter ending September 30, 2017 and
2.0
to 1.0 for fiscal quarters thereafter. The definition of consolidated interest expense utilized in the Interest Coverage Ratio excludes payments in common shares or additional indebtedness on the 1.5 Lien Notes and 1.75 Lien Term Loans. The consolidated EBITDAX and consolidated interest expense utilized in this calculation are annualized beginning with the fiscal quarter ending September 30, 2017. Therefore, the receipt of shareholder approval to pay interest through the issuance of common shares is essential to our ability to maintain compliance with this covenant. Furthermore, our ability to maintain compliance with other financial covenants under the EXCO Resources Credit Agreement would be negatively impacted if we are not able to pay interest in common shares.
We intend to seek approval for these transactions through our annual meeting of shareholders or at a special meeting of shareholders called for such purpose within the period required by the 1.5 Lien Notes and 1.75 Lien Term Loans. The shareholder approval to permit the issuance of common shares associated with the transactions requires the affirmative vote of a majority of the votes cast by the holders of our outstanding common shares. The shareholder approval to amend our charter to increase the number of shares authorized for issuance or approval to execute a reverse stock split, without a proportionate reduction of authorized shares, at the discretion of the Board of Directors, requires that holders of at least two-thirds of outstanding shares approve the proposal. However, we may waive the requirement within the 1.5 Lien Notes and 1.75 Lien Notes to obtain shareholder approval to amend our charter at our sole discretion. Certain of our related parties and members of our Board of Directors hold approximately
46%
of the total common shares outstanding as of December 31, 2016. The issuance of the 1.5 Lien Notes and the exchange transactions involving the 1.75 Lien Term Loans were approved by a special committee of the Board of Directors consisting of the sole disinterested member of the Board of Directors. The Board of Directors authorized and approved the transactions based on the recommendation of the special committee. However, there is no assurance that the proposals will be approved. Therefore, the receipt of shareholder approval was deemed to be outside of our control in accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 205-40,
Going Concern
and our ability to pay interest in common shares was not factored into our analysis regarding our ability to continue as a going concern. If we are not able to obtain shareholder approval to permit the transactions, and are not able to pay interest in common shares, it is probable that we will not meet the minimum requirement under the Interest Coverage Ratio for the twelve-month period following the date of these Consolidated Financial Statements.
If we are not able to comply with our debt covenants or do not have sufficient Liquidity to conduct our business operations in future periods, we may be required, but unable, to refinance all or part of our existing debt, seek covenant relief from our lenders, sell assets, incur additional indebtedness, or issue equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the EXCO Resources Credit Agreement. Therefore, our ability to continue our planned principal business operations would be dependent on the actions of our lenders or obtaining additional debt and/or equity financing to repay outstanding indebtedness under the EXCO Resources Credit Agreement. These factors raise substantial doubt about our ability to continue as a going concern.
If the shareholder approval is obtained, we may elect to pay interest on the 1.5 Lien Notes and 1.75 Lien Term Loans in common shares at our sole discretion until December 31, 2018. If this occurs, our plans would be to pay interest on the 1.5 Lien Notes and 1.75 Lien Term Loans in common shares during this period and we expect that we would have sufficient Liquidity and maintain compliance with our debt covenants for the twelve-month period following the date of these Consolidated Financial Statements. In addition, we are evaluating the potential divestiture of our assets in South Texas to further improve our Liquidity. There is no assurance any such transactions will occur.
The accompanying Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.
Revisions of prior period information
On August 19, 2016, we formed Raider Marketing, LP ("Raider") through an internal merger to provide marketing services to EXCO and pursue independent business opportunities. Raider is a wholly owned subsidiary of EXCO and is the contractual counterparty by operation of Texas law to all of EXCO's gathering, transportation and marketing contracts in Texas and Louisiana. In connection with the formation of Raider and the Company's plans to pursue additional marketing opportunities, we have revised our presentation of third party natural gas purchases and sales to report these costs and revenues on a gross basis in the accompanying statements of operations in accordance with FASB ASC 605,
Revenue Recognition,
beginning in the third quarter of 2016. Third party purchases and sales are now reported gross as "Purchased natural gas" expenses and "Purchased natural gas and marketing" revenues, respectively. Purchased natural gas and marketing revenues include revenue we receive as a result of selling natural gas that we purchase from third parties and marketing fees we receive from third parties. Purchased natural gas expenses include purchases from third parties plus an allocation of transportation costs. The transportation costs allocated to the third party purchases relate to our firm transportation agreements with unutilized commitments; therefore, the utilization of this transportation reduces the unutilized commitments that would have otherwise been allocated to our net share of production and incurred by EXCO.
We previously reported these transactions on a net basis in the financial statements due to the materiality associated with the income or loss generated from these purchases and sales, and the historical insignificance of the Company's marketing activities involving the purchases and sales of third party natural gas to our operations. The net effect of these revisions did not impact our previously reported net income or loss, shareholders’ equity or cash flows. The Company evaluated the materiality of the revisions based on ASC 250,
Accounting Changes and Error Corrections
, and concluded the revisions to be immaterial corrections of an error.
The following table reflects the revisions to the following annual periods:
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Year ended
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(in thousands)
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December 31, 2015
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December 31, 2014
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Natural gas revenues, previously reported
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$
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225,544
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$
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463,953
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Revision of third party natural gas purchases and sales
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927
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715
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Natural gas revenues, as currently reported
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$
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226,471
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$
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464,668
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Purchased natural gas and marketing revenues
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$
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26,442
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$
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34,933
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Purchased natural gas expenses
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$
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27,369
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$
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35,648
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2.
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Summary of significant accounting policies
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Principles of consolidation
We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31,
2016
and
2015
and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31,
2016
,
2015
and
2014
. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated.
We report our interests in oil and natural gas properties using the proportional consolidation method of accounting. We reported our
25.5%
interest in Compass Production Partners, L.P. ("Compass") using proportional consolidation for the period from its formation on February 14, 2013 to the sale of our interests on October 31, 2014. See further discussion in "Note 3. Acquisitions, divestitures and other significant events."
Management estimates
In preparing the consolidated financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates.
Cash equivalents
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Restricted cash
The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with Shell that is used to fund our share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana. The restricted cash balance at December 31, 2015 also included accrued fees payable to Energy Strategic Advisory Services LLC ("ESAS") which were paid during 2016 upon completion of ESAS's entire first year of service and required investment with EXCO. See "Note 13. Related party transactions" for further discussion of the services and investment agreement with ESAS.
Concentration of credit risk and accounts receivable
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both
December 31, 2016
and
2015
. We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.
For the years ended
December 31, 2016
,
2015
and
2014
, sales to
BG Energy Merchants LLC
, and subsequently to Shell Energy North America US, LP, accounted for approximately
24%
,
20%
and
34%
, respectively, of total consolidated revenues.
BG Energy Merchants LLC
was a subsidiary of BG Group, plc ("BG Group") until the acquisition of BG Group by Shell in early 2016. For the years ended
December 31, 2016
,
2015
and
2014
, Chesapeake Energy Marketing Inc. accounted for approximately
32%
,
38%
and
31%
respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake").
Derivative financial instruments
We use derivative financial instruments to mitigate the impacts of commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow. FASB ASC, Topic 815,
Derivatives and Hedging,
("ASC 815"), requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its estimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments and, as a result, recognize the change in a derivative's estimated fair value in earnings as a component of other income or expense. Our derivative financial instruments are not held for trading purposes.
Oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development and major development projects, collectively totaled
$97.1 million
and
$115.4 million
as of
December 31, 2016
and
2015
, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations. There were
no
impairments of unproved properties during
2016
and 2014 and we impaired
$88.1 million
of unproved properties during 2015. The impairment was recorded to reflect the estimated fair value of our undeveloped properties as a result of the decline in oil and natural gas prices. The impairment also included certain expiring acreage that was no longer part of our drilling plans. See "Note 6. Fair value measurements" for further discussion.
We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20
, Capitalization of Interest
. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the relationship between capitalized costs and Proved Reserves.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at
10%
, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.
The ceiling test for each period presented 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 12 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)
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Natural gas (per Mmbtu)
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December 31, 2016
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$
|
42.75
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|
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$
|
2.48
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December 31, 2015
|
|
50.28
|
|
|
2.59
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|
December 31, 2014
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|
94.99
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|
|
4.35
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For the year ended
December 31, 2016
, we recognized impairments to our proved oil and natural gas properties of
$160.8 million
. The impairments were primarily due to the decline in oil and natural gas prices. Furthermore, the fixed costs associated with certain gathering and transportation contracts continue to have a significant impact on the present value of our Proved Reserves. For the year ended December 31, 2015, we recognized impairments to our proved oil and natural gas
properties of
$1.2 billion
. The impairments were primarily due to the decline in oil and natural gas prices partially offset by upward revisions in the oil and natural gas reserves primarily as a result of modifications to our well design in the North Louisiana and East Texas regions. For the year ended December 31, 2014, we did
no
t recognize an impairment to our proved oil and natural gas properties.
All of our Proved Undeveloped Reserves were reclassified to unproved during the first quarter of 2016 due to the uncertainty regarding the financing required to develop these reserves that existed on March 31, 2016. These reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2016. A significant amount of our Proved Undeveloped Reserves that were reclassified to unproved remain economic at current prices, and we may report Proved Undeveloped Reserves in future filings if we determine we have the financial capability to execute a development plan.
Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations.
The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.
Other property and equipment
Other property and equipment is primarily comprised of office, field and other equipment which are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from
3
to
15
years and the surface acreage we own in our South Texas region.
Goodwill
In accordance with FASB ASC 350-20,
Intangibles-Goodwill and Other
("ASC 350-20"), goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations.
We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies. As part of the determination of the fair value of our reporting unit, we corroborate the results of the valuation model through a comparison to our enterprise value that is calculated as the combined market capitalization of our equity plus the fair value of our debt.
As a result of testing, the fair value of our business significantly exceeded the carrying value of net assets at
December 31, 2016
and we did not record an impairment charge for the periods ending
December 31, 2016
,
2015
or
2014
.
Asset retirement obligations
We apply FASB ASC 410-20,
Asset Retirement and Environmental Obligations
("ASC 410-20") to account for estimated future plugging and abandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws.
The following is a reconciliation of our asset retirement obligations for the periods indicated:
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December 31,
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(in thousands)
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2016
|
|
2015
|
|
2014
|
Asset retirement obligations at beginning of period
|
|
$
|
41,648
|
|
|
$
|
36,755
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|
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$
|
42,954
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Activity during the period:
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Liabilities incurred during the period
|
|
—
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|
|
881
|
|
|
576
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|
Revisions in estimated assumptions
|
|
175
|
|
|
3,215
|
|
|
—
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|
Liabilities settled during the period
|
|
(140
|
)
|
|
(293
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)
|
|
(33
|
)
|
Adjustment to liability due to acquisitions
|
|
1
|
|
|
180
|
|
|
107
|
|
Adjustment to liability due to divestitures (1)
|
|
(32,605
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)
|
|
(1,367
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)
|
|
(9,539
|
)
|
Accretion of discount
|
|
2,210
|
|
|
2,277
|
|
|
2,690
|
|
Asset retirement obligations at end of period
|
|
11,289
|
|
|
41,648
|
|
|
36,755
|
|
Less current portion
|
|
344
|
|
|
845
|
|
|
1,769
|
|
Long-term portion
|
|
$
|
10,945
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|
|
$
|
40,803
|
|
|
$
|
34,986
|
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|
|
(1)
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For the year ended December 31, 2016, the adjustment to liability due to divestitures consisted primarily of
$22.6 million
and
$9.7 million
from the sales of our conventional assets located in Pennsylvania and West Virginia, respectively. For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of
$9.4 million
from the sale of our interest in Compass.
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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.
Revenue recognition and gas imbalances
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at
December 31, 2016
,
2015
and
2014
were not significant.
Gathering and transportation
We generally sell oil and natural gas under
two
types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, 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. In this case, we record the transportation cost as gathering and transportation expense. As such, our computed realized prices, before the impact of derivative financial instruments, include revenues which are reported under
two
separate bases. Gathering and transportation expenses totaled
$106.5 million
,
$99.3 million
and
$101.6 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
Capitalization of internal costs
As part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employees who are directly involved in the acquisition, appraisal, exploration, exploitation and development of oil and natural gas properties. During the years ended
December 31, 2016
,
2015
and
2014
, we capitalized
$4.0 million
,
$10.6 million
and
$15.8 million
, respectively. The capitalized amounts include
$0.8 million
,
$3.4 million
and
$5.5 million
of share-based compensation for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners of
$13.7 million
,
$13.1 million
and
$13.5 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, as a reduction of general and administrative
expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of
$5.8 million
,
$5.7 million
and
$6.4 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
In addition, we have agreements with Shell that allow us to bill each other certain personnel costs and related fees incurred on behalf of the joint ventures in the East Texas, North Louisiana and Appalachia regions. In connection with the formation of Compass, we entered into an agreement to perform certain operational, managerial, and administrative services. Compass reimbursed us for costs incurred in connection with the performance of these services based on an agreed upon service fee. As a result of the Compass sale, this agreement was terminated on October 31, 2014 and we entered into a customary transition services agreement pursuant to which EXCO provided certain transition services to Compass until April 2015. For the years ended December 31,
2016
,
2015
and
2014
, general and administrative expenses were reduced by
$7.1 million
,
$15.9 million
and
$24.7 million
, respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by Shell for their personnel and services.
Environmental costs
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes
Income taxes are accounted for in accordance with FASB ASC 740,
Income Taxes
("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings per share
We account for earnings per share in accordance with FASB ASC 260-10,
Earnings Per Share
("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"): basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period, excluding stock options, restricted share units, restricted share awards and warrants. Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not.
Equity-based compensation
Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC Topic 718,
Compensation-Stock Compensation
("ASC 718") and equity-based compensation for warrants issued to ESAS which we account for in accordance with FASB ASC Topic 505-50,
Equity-Based Payments to Non-Employees
("ASC 505-50").
ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.
Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards.
The measurement of the warrants is accounted for in accordance with ASC 505-50, which requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded
in our Consolidated Statements of Operations included as equity-based compensation expense. See "Note 11. Equity-based compensation" for additional information on the warrants issued to ESAS.
Recent accounting pronouncements
In February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. These transactions will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the potential impact of ASU 2016-02 and expect it will have a material impact on our consolidated financial condition and results of operations upon adoption.
In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323):
Simplifying the Transition to the Equity Method of Accounting
("ASU 2016-07"). ASU 2016-07 eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We do not currently have significant investments that are accounted for by a method other than the equity method and do not expect ASU 2016-07 to have a significant impact on our consolidated financial condition and results of operations.
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718):
Improvements to Employee Share-Based Payment Accounting
("ASU 2016-09"). ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. ASU 2016-07 did not have an impact on our financial condition and results of operations upon adoption in the fourth quarter of 2016. The Company will continue with its current practice of estimating forfeitures instead of accounting for forfeitures when they occur, as allowed by ASU 2016-07.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230):
Classification of Certain Cash Receipts and Cash Payments
("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-15 on our consolidated financial condition and results of operations.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740):
Intra-Entity Transfers of Assets Other Than Inventory
("ASU 2016-16"). The amendments in this update require that an entity recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Consequently, the amendments in this update eliminate the exception for an intra-entity transfer of an asset other than inventory. ASU 2016-16 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We are currently assessing the potential impact of ASU 2016-16 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 believe the impact of the adoption of this ASU will change the presentation of our beginning and ending cash balances on our Consolidated Statements of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing and operating activities on our Consolidated Statements of Cash Flows.
In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805):
Clarifying the Definition of a Business
("ASU 2017-07"). 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 it's not met, the entity then evaluates whether the set meets the requirement that a business include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. We are currently assessing the potential impact of ASU 2017-01 on our consolidated financial condition and results of operations.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350):
Simplifying the Test for Goodwill Impairment
("ASU 2017-04"). ASU 2017-04 eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. ASU 2017-04 is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. We are currently assessing the impact of ASU 2017-04 and date of adoption.
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 ("IASB") 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. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method.
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606):
Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
("ASU 2016-08"). ASU 2016-08 does not change the core principle of Topic 606 but clarifies the implementation guidance on principal versus agent considerations. ASU 2016-08 is effective for annual and interim periods beginning after December 15, 2017.
In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606):
Identifying Performance Obligations and Licensing
("ASU 2016-10"). ASU 2016-10 does not change the core principle of Topic 606 but clarifies the following two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for annual and interim periods beginning after December 15, 2017.
In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815):
Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting
("ASU 2016-11"). The SEC Staff is rescinding the following SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Specifically, registrants should not rely on the following SEC Staff Observer comments upon adoption of Topic 606: a) Revenue and Expense Recognition for Freight Services in Process which is codified in 605-20-S99-2; b) Accounting for Shipping and Handling Fees and Costs, which is codified in paragraph 605-45-S99-1; c) Accounting for Consideration Given by a Vendor to a Customer, which is codified in paragraph 605-50-S99-1 and d) Accounting for Gas-Balancing Arrangements (that is, use of the “entitlements method”), which is codified in paragraph 932-10-S99-5. We do not use the entitlements method of accounting and are not impacted by this specific SEC Staff Observer comment; however, we are assessing the potential impact of other SEC Staff Observer comments included in ASU 2016-11 on our consolidated financial condition and results of operations.
In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606):
Narrow-Scope Improvements and Practical Expedients
("ASU 2016-12"). ASU 2016-12 does not change the core principle of Topic 606 but improves the following aspects of Topic 606: assessing collectability, presentation of sales taxes, noncash considerations, completed contracts and contract modifications at transaction. ASU 2016-12 is effective for annual and interim periods beginning after December 15, 2017.
We are currently assessing the impact of ASU 2014-09 and the related updates and clarifications and are performing a review of the new guidance. We intend to adopt ASU 2014-09 and the related updates for the interim and annual periods beginning after December 15, 2017. During 2017, we plan to assess our contracts and consider the method of adoption. We are currently unable to quantify the impact the standard will have on our consolidated financial condition and results of operations; however, based on our preliminary analysis, we do not believe this standard will have a material impact, if any, on our consolidated financial condition and results of operations.
|
|
3.
|
Acquisitions, divestitures and other significant events
|
2016 Divestitures
South Texas transaction
On May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our interests in
four
producing wells for
$11.5 million
, after final purchase price adjustments. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement.
Conventional asset divestitures
On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and received an overriding royalty interest in each well. In addition, we retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the six months ended June 30, 2016, the divested assets produced approximately
6
Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated a net loss of less than
$0.1 million
. The asset retirement obligations related to the divested wells were
$22.6 million
on July 1, 2016.
On October 3, 2016, we closed the sale of our interests in shallow conventional assets located primarily in West Virginia for approximately
$4.5 million
, subject to customary post-closing purchase price adjustments. We retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the nine months ended September 30, 2016, the divested assets produced approximately
4
Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated net income of
$0.7 million
. The asset retirement obligations related to the divested wells were
$9.7 million
on October 3, 2016.
In conjunction with the sales of our shallow conventional assets in Pennsylvania and West Virginia, the Company's field employee count in the Appalachia region has been reduced by
85%
since December 31, 2015.
The divestitures of our interests during 2016 did not significantly alter the relationship between our capitalized costs and Proved Reserves and were accounted for as an adjustment of capitalized costs with no gain or loss recognized in accordance with Rule 4-10(c)(6)(i) of Regulation S-X.
2015 Acquisitions and termination of Participation Agreement
In July 2013, we entered into a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale ("Participation Agreement"). The Participation Agreement required us to offer to purchase our joint venture partner's working interest in wells that have been on production for at least
one year
. The offers were made on a quarterly basis for a group of wells based on prices defined in the Participation Agreement, subject to specific well criteria and return hurdles.
We closed the first acquisition of our joint venture partner's interest in
3
gross (
1.4
net) wells on March 11, 2015 for a total purchase price of
$7.6 million
.
During the fourth quarter of 2015, our Eagle Ford joint venture partner purported to accept our offer under the Participation Agreement to purchase interests in
21
gross (
10.3
net) wells for
$42.7 million
, subject to purchase price adjustments subsequent to the effective date of June 30, 2015. We notified our joint venture partner that we did not intend to close this acquisition as our partner's purported acceptance had not been received in a timely manner under the terms of the Participation Agreement, and our joint venture partner filed a petition for injunctive relief and damages alleging that, among other things, we breached our obligation under the Participation Agreement. In addition, subsequent offers were also in dispute for various reasons.
On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed after a final judgment order was entered in response to the parties’ joint motion to dismiss the case with prejudice. Among other things, the settlement provided a full release for any claims, rights, demands, damages and causes of action that either party has asserted or could have asserted for any breach of the Participation Agreement. As part of the settlement, the parties amended and restated the Participation Agreement to (i) eliminate our requirement to offer to purchase our joint venture partner's interests in certain wells each quarter, (ii) eliminate our requirement to convey a portion of our working interest to our joint venture partner upon commencing development of future locations, (iii) terminate the area of mutual interest, which required either party acquiring an interest in non-producing acreage included in certain areas to provide notice of the acquisition to the non-acquiring party and allowed the non-acquiring party to acquire a proportionate share in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wells and certain undeveloped locations in South Texas (“Transferred Interests”), effective May 1, 2016 and (v) modify or eliminate certain other provisions. The Participation Agreement was terminated on December 1, 2016 upon final settlement of the agreement.
We recorded a loss in "Other operating items" in the Consolidated Statements of Operations, and a corresponding credit to the "Proved developed and undeveloped oil and natural gas properties" in our Consolidated Balance Sheet during 2016. The fair value of the Transferred Interests was
$23.2 million
as of July 25, 2016 based on a discounted cash flow model of the estimated reserves using NYMEX forward strip prices. See "Note 6. Fair value measurements" for additional information. The net production from the Transferred Interests was approximately
350
Bbls of oil per day during June 2016.
2014 Divestitures
Permian Basin transaction
On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately
$68.2 million
, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement.
Compass divestiture
On October 31, 2014, we closed the sale of our entire interest in Compass to Harbinger Group, Inc. ("HGI") for
$118.8 million
in cash. We used a portion of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Prior to the closing of the sale, we reported our
25.5%
interest in Compass using proportional consolidation. Our consolidated assets and liabilities were reduced by our proportionate share of Compass's net assets of
$31.4 million
which included our proportionate share of the Compass's indebtedness of
$83.2 million
on October 31, 2014.
The sale of our interest in Compass did not significantly alter the relationship between our capitalized costs and Proved Reserves and was accounted for as an adjustment of capitalized costs with no gain or loss recognized in accordance with Rule 4-10(c)(6)(i) of Regulation S-X. As a result, our capitalized costs were further reduced by
$87.4 million
. Following the closing, EXCO was no longer required to offer acquisition opportunities to Compass or any of its affiliates.
|
|
4.
|
Derivative financial instruments
|
Our primary objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.
The table below outlines the classification of our derivative financial instruments on our Consolidated Balance Sheets and their financial impact on our Consolidated Statements of Operations.
Fair Value of Derivative Financial Instruments
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
December 31, 2015
|
Derivative financial instruments - Current assets
|
|
$
|
—
|
|
|
$
|
39,499
|
|
Derivative financial instruments - Long-term assets
|
|
482
|
|
|
6,109
|
|
Derivative financial instruments - Current liabilities
|
|
(27,711
|
)
|
|
(16
|
)
|
Derivative financial instruments - Long-term liabilities
|
|
(464
|
)
|
|
—
|
|
Net derivative financial instruments
|
|
$
|
(27,693
|
)
|
|
$
|
45,592
|
|
The Effect of Derivative Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
2014
|
Gain (loss) on derivative financial instruments
|
|
$
|
(34,137
|
)
|
|
$
|
75,869
|
|
|
$
|
87,665
|
|
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 includes both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Consolidated Balance Sheets' fair value amounts.
Our oil and natural gas derivative instruments are comprised of the following instruments:
Swaps
: These contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
Collars
: A collar is a combination of options including a sold call and a purchased put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with downside protection through the put option. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess. If the market price is above the strike price of the sold call at the time of settlement, we pay the counterparty the excess. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.
In the fourth quarter of 2016, a counterparty exercised its option under swaption contracts and entered into swap contracts covering
7,300
Bbtu of natural gas at an average price of
$2.76
per Mmbtu during 2017. The swaption contract gave our trading counterparty the right, but not the obligation, to enter into a swap contract for an agreed quantity of oil or natural gas from us at a certain time and fixed price in the future.
We place our derivative financial instruments with the financial institutions that are lenders under the EXCO Resources Credit Agreement that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. Our credit rating and financial condition may restrict our ability to enter into certain types of derivative financial instruments and limit the maturity of the contracts with counterparties. We have historically entered into derivative financial instruments with the financial institutions that are lenders
under the EXCO Resources Credit Agreement. Therefore, our ability to enter into derivative financial instruments may be limited beyond the maturity of the EXCO Resources Credit Agreement in July 2018. We are currently evaluating alternatives to enter into derivative financial instruments beyond this date, which may include counterparties that are not lenders under the EXCO Resources Credit Agreement. These alternatives may include agreements with counterparties on a secured or unsecured basis. If we enter into derivative financial instruments that require us to post collateral, this could further constrain our liquidity. Our derivative contracts also contain rights that could result in the early termination of our derivative contracts and cash payments to our counterparties due to an event of default under the EXCO Resources Credit Agreement.
The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars in thousands, except prices)
|
|
Volume Bbtu/Mbbl
|
|
Weighted average strike price per Mmbtu/Bbl
|
|
Fair value at December 31, 2016
|
Natural gas:
|
|
|
|
|
|
|
Swaps:
|
|
|
|
|
|
|
2017
|
|
38,300
|
|
|
3.02
|
|
|
(21,986
|
)
|
2018
|
|
3,650
|
|
|
3.15
|
|
|
18
|
|
Collars:
|
|
|
|
|
|
|
2017
|
|
10,950
|
|
|
|
|
$
|
(4,652
|
)
|
Sold call
|
|
|
|
3.28
|
|
|
|
Purchased put
|
|
|
|
2.87
|
|
|
|
Total natural gas
|
|
|
|
|
|
$
|
(26,620
|
)
|
Oil:
|
|
|
|
|
|
|
Swaps:
|
|
|
|
|
|
|
2017
|
|
183
|
|
|
$
|
50.00
|
|
|
$
|
(1,073
|
)
|
Total oil
|
|
|
|
|
|
$
|
(1,073
|
)
|
Total oil and natural gas derivative financial instruments
|
|
|
|
|
|
$
|
(27,693
|
)
|
At
December 31, 2015
, we had outstanding swap contracts covering
49,370
Bbtu of natural gas and
915
Mbbls of oil.
At
December 31, 2016
, the average forward NYMEX WTI oil price per Bbl for the calendar year
2017
was
$56.19
and the average forward NYMEX HH natural gas prices per Mmbtu for the calendar years
2017
and
2018
were
$3.61
and
$3.14
, respectively.
Our derivative financial instruments covered approximately
57%
and
68%
of production volumes
for the years ended
December 31, 2016
and
2015
.
The carrying value of our total debt is summarized as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
December 31, 2015
|
EXCO Resources Credit Agreement
|
|
$
|
228,592
|
|
|
$
|
67,492
|
|
Exchange Term Loan
|
|
590,477
|
|
|
641,172
|
|
Fairfax Term Loan
|
|
300,000
|
|
|
300,000
|
|
2018 Notes
|
|
131,576
|
|
|
158,015
|
|
Unamortized discount on 2018 Notes
|
|
(520
|
)
|
|
(932
|
)
|
2022 Notes
|
|
70,169
|
|
|
222,826
|
|
Deferred financing costs, net
|
|
(11,756
|
)
|
|
(18,294
|
)
|
Total debt, net
|
|
1,308,538
|
|
|
1,370,279
|
|
Less amounts due within one year
|
|
50,000
|
|
|
50,000
|
|
Total debt due after one year
|
|
$
|
1,258,538
|
|
|
$
|
1,320,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
(in thousands)
|
|
Carrying value
|
|
Deferred reduction in carrying value
|
|
Unamortized discount/deferred financing costs
|
|
Principal balance
|
EXCO Resources Credit Agreement
|
|
$
|
228,592
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
228,592
|
|
Exchange Term Loan
|
|
590,477
|
|
|
(190,477
|
)
|
|
—
|
|
|
400,000
|
|
Fairfax Term Loan
|
|
300,000
|
|
|
—
|
|
|
—
|
|
|
300,000
|
|
2018 Notes
|
|
131,056
|
|
|
—
|
|
|
520
|
|
|
131,576
|
|
2022 Notes
|
|
70,169
|
|
|
—
|
|
|
—
|
|
|
70,169
|
|
Deferred financing costs, net
|
|
(11,756
|
)
|
|
—
|
|
|
11,756
|
|
|
—
|
|
Total debt
|
|
$
|
1,308,538
|
|
|
$
|
(190,477
|
)
|
|
$
|
12,276
|
|
|
$
|
1,130,337
|
|
Terms and conditions of each of these debt obligations are discussed below.
Recent Transactions
On
March 15, 2017
, we closed a series of transactions that consisted of (i) the issuance of 1.5 Lien Notes, (ii) exchange of
$682.8 million
in aggregate principal amount of our outstanding Second Lien Term Loans for a like principal amount of 1.75 Lien Term Loans and (iii) the issuance of warrants to the investors of the 1.5 Lien Notes and certain holders of the 1.75 Lien Term Loan. Under the terms of the indenture governing the 1.5 Lien Notes and the agreement governing the 1.75 Lien Term Loans, we may, under certain circumstances, make interest payments on the 1.5 Lien Notes and the 1.75 Lien Term Loans in cash, common shares or additional indebtedness. In connection with the closing of these transactions, the EXCO Resources Credit Agreement was amended to reduce the borrowing base to
$150.0 million
, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, and modify certain financial covenants. See further discussion of these transactions as part of "Note 18. Subsequent Events".
Tender Offer and open market repurchases
On August 24, 2016, we completed a cash tender offer for our outstanding senior unsecured notes ("Tender Offer") that resulted in the repurchase of an aggregate of
$101.3 million
in principal amount of the 2022 Notes for an aggregate purchase price of
$40.0 million
. Holders of the 2022 Notes that were accepted for payment in the Tender Offer also received accumulated and unpaid interest. The Tender Offer was funded with the borrowings under the EXCO Resources Credit Agreement.
For the year ended
December 31, 2016
, we repurchased an aggregate of
$26.4 million
and
$152.7 million
in principal amount of the senior unsecured notes due September 15, 2018 ("2018 Notes") and senior unsecured notes due April 15, 2022 (“2022 Notes”), respectively, with an aggregate of
$53.3 million
in cash through the Tender Offer and open market repurchases. These repurchases resulted in a net gain on extinguishment of debt of
$119.5 million
for the year ended
December 31, 2016
.
EXCO Resources Credit Agreement
As of
December 31, 2016
, the EXCO Resources Credit Agreement had
$228.6 million
of outstanding indebtedness and a borrowing base of
$325.0 million
. The Company's available borrowing capacity was
$46.2 million
as of December 31, 2016 since we were not permitted to request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed
$285.0 million
, including letters of credit, until the effective date of the next redetermination.
The maturity date of the EXCO Resources Credit Agreement is
July 31, 2018
. The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranges from London Interbank Offered Rate ("LIBOR") plus 225 bps to 325 bps (or alternate base rate ("ABR") plus 125 bps to 225 bps), depending on our borrowing base usage. On
December 31, 2016
, our interest rate was approximately
3.5%
.
As of
December 31, 2016
, we were in compliance with the financial covenants (defined in the EXCO Resources Credit Agreement), which required that we:
|
|
•
|
maintain a Consolidated Current Ratio of at least
1.0
to
1.0
as of the end of any fiscal quarter. The consolidated current assets utilized in this ratio include unused commitments under the EXCO Resources Credit Agreement. As of December 31, 2016, the unused commitments were based on the Company's borrowing base of
$325.0 million
;
|
|
|
•
|
maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least
1.25
to 1.0 as of the end of any fiscal quarter. The consolidated interest expense utilized in the Interest Coverage Ratio is calculated in accordance with GAAP; therefore, this excludes cash payments under the terms of the Exchange Term Loan (as defined below), whether designated as interest or as principal amount, that reduce the carrying amount and are not recognized as interest expense; and
|
|
|
•
|
not permit a Senior Secured Indebtedness Ratio to be greater than
2.5
to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans and any other secured indebtedness subordinated to the EXCO Resources Credit Agreement.
|
These financial covenants were modified in connection with the amendment to the EXCO Resources Credit Agreement on
March 15, 2017
. Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than
80%
of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than
100%
of forecasted production from total Proved Reserves, as defined in the agreement, for any month during the first two years of the forthcoming five-year period,
90%
of forecasted production from total Proved Reserves for any month during the third year of the forthcoming five-year period and
85%
of forecasted production from total Proved Reserves for any month during the fourth and fifth years of the forthcoming five-year period.
Second Lien Term Loans
On October 26, 2015, we closed a
12.5%
senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited ("Fairfax") in the aggregate principal amount of
$300.0 million
("Fairfax Term Loan"). We also closed a
12.5%
senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of
$291.3 million
on October 26, 2015 and
$108.7 million
on November 4, 2015 (“Exchange Term Loan"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60,
Troubled Debt Restructuring by Debtors
. The future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal. All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. As such, our reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan.
The Second Lien Term Loans mature on October 26, 2020 with interest payable on the last day in each calendar quarter. The Second Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly held equity investments with Shell, and are secured by second-priority liens on substantially all of EXCO’s assets securing the indebtedness under the EXCO Resources Credit Agreement. The Second Lien Term Loans rank (i) junior to the debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu to one another and (iii) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and the 2022 Notes, to the extent of the value of collateral.
The agreements governing the Second Lien Term Loans contain covenants that, subject to certain exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things:
|
|
•
|
pay dividends or make other distributions or redeem or repurchase our common shares;
|
|
|
•
|
prepay, redeem or repurchase certain debt;
|
|
|
•
|
enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advances to us or transfer assets to us;
|
|
|
•
|
engage in asset sales or substantially alter the business that we conduct, unless the proceeds are utilized to prepay the Second Lien Term Loans, reduce priority lien indebtedness, or reinvest in the acquisition or development of oil and gas properties;
|
|
|
•
|
enter into transactions with affiliates;
|
|
|
•
|
consolidate, merge or dispose of assets;
|
|
|
•
|
enter into sale/leaseback transactions.
|
In addition, the term loan agreement governing the Exchange Term Loan prohibited us from incurring, among other things and subject to certain exceptions:
|
|
•
|
debt under credit facilities, as defined in the term loan credit agreement governing the Exchange Term Loan, in excess of the greatest of (i)
$375.0 million
plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, (ii) the borrowing base under the EXCO Resources Credit Agreement and (iii)
30%
of modified adjusted consolidated net tangible assets (as defined in the agreement);
|
|
|
•
|
second lien debt in excess of
$700.0 million
; and
|
|
|
•
|
unsecured debt where on the date of such incurrence or after giving effect to such incurrence, our consolidated coverage ratio (as defined in the agreement) is or would be less than
2.25
to 1.0.
|
The term loan agreement governing the Fairfax Term Loan prohibited us from incurring, among other things and subject to certain exceptions:
|
|
•
|
debt under credit facilities, as defined in the term loan credit agreement governing the Fairfax Term Loan, in excess of
$375.0 million
plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, provided that such indebtedness may not exceed
$500.0 million
, unless we obtain consent from the administrative agent;
|
|
|
•
|
second lien debt, other than the Exchange Term Loan, in an amount to be agreed upon with the administrative agent;
|
|
|
•
|
junior lien debt, unless such debt is being used to refinance the 2018 Notes or the 2022 Notes or the terms and conditions of such junior lien debt are approved by the administrative agent; and
|
|
|
•
|
unsecured debt, unless we obtain consent from the administrative agent.
|
In addition, under the term loan credit agreement governing the Fairfax Term Loan, a change of control constitutes an event of default, which, subject to certain limitations, may allow the Fairfax Term Loan lenders to declare the Fairfax Term Loan to be due and payable, in whole or in part, including accrued but unpaid interest thereon, plus an amount equal to all interest payments that would have accrued through the Fairfax Term Loan maturity date. Under the term loan credit agreement governing the Exchange Term Loan, in the event of a change of control EXCO is required to offer to repurchase the Exchange Term Loan at
101%
of the face value of the Exchange Term Loan.
In connection with the Second Lien Term Loans, on October 26, 2015, EXCO entered into an intercreditor agreement governing the relationship between EXCO’s lenders and the holders of any other lien obligations that EXCO may issue in the future and a collateral trust agreement governing the administration and maintenance of the collateral securing the Second Lien Term Loans.
The holders of the Fairfax Term Loan and holders of
$382.8 million
of the Exchange Term Loan consented to the exchange for 1.75 Lien Term Loans that closed on
March 15, 2017
. As a result, the aggregate principal amount outstanding under the Exchange Term Loan was reduced to
$17.2 million
subsequent to the exchange transactions. The credit agreement governing the Exchange Term Loan was amended to eliminate substantially all of the restrictive covenants and events of default included in the agreement.
2018 Notes
The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with Shell. Our equity investments, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.
During 2015, EXCO repurchased an aggregate
$551.2 million
of the 2018 Notes in exchange for certain holders of the 2018 Notes to act as lenders under the Exchange Term Loan. Additionally, as of
December 31, 2016
, we had repurchased a total of
$67.2 million
in principal amount of the 2018 Notes for an aggregate of
$18.8 million
in a series of open market repurchases. As a result of the repurchases, the aggregate principal amount of outstanding 2018 Notes was reduced to
$131.6 million
as of
December 31, 2016
. Interest accrues at
7.5%
per annum and is payable semi-annually in arrears on March 15 and September 15 of each year.
The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:
|
|
•
|
incur or guarantee additional debt and issue certain types of preferred shares;
|
|
|
•
|
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
|
|
|
•
|
make certain investments;
|
|
|
•
|
create liens on our assets;
|
|
|
•
|
enter into sale/leaseback transactions;
|
|
|
•
|
create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
|
|
|
•
|
engage in transactions with our affiliates;
|
|
|
•
|
transfer or issue shares of stock of subsidiaries;
|
|
|
•
|
transfer or sell assets; and
|
|
|
•
|
consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
|
On November 25, 2015, the Company obtained the requisite consents to amend the indenture governing the 2018 Notes. Following the receipt of the requisite consents, EXCO entered into a supplemental indenture which, among other things, eliminated the reduction in the amount of secured indebtedness permitted under the EXCO Resources Credit Agreement upon principal payments which results in a permanent reduction in borrowing capacity of EXCO. As a result, the amount of secured indebtedness permitted under the EXCO Resources Credit Agreement cannot exceed the greater of
$1.2 billion
or a calculation based on the value of our assets.
2022 Notes
The 2022 Notes were issued at
100.0%
of the principal amount and bear interest at a rate of
8.5%
per annum, payable in arrears on April 15 and October 15 of each year. During 2015, EXCO repurchased an aggregate
$277.2 million
in principal amount of the 2022 Notes in exchange for certain holders of the 2022 Notes becoming lenders under the Exchange Term Loan. On August 24, 2016, we completed the Tender Offer that resulted in the repurchases of an aggregate of
$101.3 million
in principal amount of the 2022 Notes for an aggregate purchase price of
$40.0 million
. As of December 31, 2016, through the Tender Offer and a series of open market repurchases, we had repurchased a total of
$152.7 million
in principal amount of the 2022 Notes for an aggregate of
$46.5 million
. As a result of the repurchases, the aggregate principal amount of outstanding 2022 Notes was reduced to
$70.2 million
as of December 31, 2016.
In conjunction with the Tender Offer, we solicited consents from the registered holders of the 2022 Notes to amend certain terms of the indenture governing the 2022 Notes. Following the consummation of the consent solicitation, we entered into a supplemental indenture governing the 2022 Notes to amend the definition of “Credit Facilities” to include debt securities as a permitted form of additional secured indebtedness, in addition to the term loans and other credit facilities currently permitted.
The 2022 Notes rank equally in right of payment to any existing and future senior unsecured indebtedness of the Company (including the 2018 Notes) and are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries that are guarantors of the indebtedness under the EXCO Resources Credit Agreement. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022 Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes.
|
|
6.
|
Fair value measurements
|
We value our derivatives and other financial instruments according to FASB ASC 820,
Fair Value Measurements and Disclosures
("ASC 820")
, 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.
Fair value of derivative financial instruments
The fair value of our derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers. During the years ended
December 31, 2016
and
2015
there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of
December 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Oil and natural gas derivative financial instruments
|
|
$
|
—
|
|
|
$
|
(27,693
|
)
|
|
$
|
—
|
|
|
$
|
(27,693
|
)
|
|
|
December 31, 2015
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Oil and natural gas derivative financial instruments
|
|
$
|
—
|
|
|
$
|
45,592
|
|
|
$
|
—
|
|
|
$
|
45,592
|
|
We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis on our Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net 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 valuation of our commodity price derivatives, represented by oil and natural gas swaps and collar contracts, is discussed below.
Oil derivatives
. Our oil derivatives are swap contracts for notional barrels of oil at fixed NYMEX oil index prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for oil index prices, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.
Natural gas derivatives
. Our natural gas derivatives consisted of swap and collar contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for natural gas, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rates of volatility inherent in the option contracts. The implied rates of volatility were determined based on the average of historical HH natural gas prices.
See further details on the fair value of our derivative financial instruments in “Note 4. Derivative financial instruments”.
Fair value of other financial instruments
Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature.
The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
The estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan 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 Exchange Term Loan and the Fairfax Term Loan have been calculated based on quoted prices obtained from third-party pricing sources and are classified as Level 2.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
2018 Notes
|
|
$
|
79,028
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
79,028
|
|
2022 Notes
|
|
35,260
|
|
|
—
|
|
|
—
|
|
|
35,260
|
|
Exchange Term Loan
|
|
—
|
|
|
294,000
|
|
|
—
|
|
|
294,000
|
|
Fairfax Term Loan
|
|
—
|
|
|
222,000
|
|
|
—
|
|
|
222,000
|
|
|
|
December 31, 2015
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
2018 Notes
|
|
$
|
43,170
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
43,170
|
|
2022 Notes
|
|
48,376
|
|
|
—
|
|
|
—
|
|
|
48,376
|
|
Exchange Term Loan
|
|
—
|
|
|
278,000
|
|
|
—
|
|
|
278,000
|
|
Fairfax Term Loan
|
|
—
|
|
|
208,500
|
|
|
—
|
|
|
208,500
|
|
Other fair value measurements
During 2016, we impaired
$4.9 million
of our investment in a midstream company in the East Texas and North Louisiana regions that we account for under the cost method of accounting. The estimated fair value of our cost method investment was determined based on transaction multiples for similar companies. We also impaired
$4.7 million
of our equity method investment in a midstream company in the Appalachia region and
$1.7 million
of our equity method investment in OPCO. The estimated fair value of our equity method investment in a midstream company in the Appalachia region 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. The estimated fair value of OPCO was determined based on trading metrics of peer companies. The impairments of our cost and equity method investments were primarily a result of limited development activity in the regions. The impairments were recorded to reduce the carrying values to the fair values and were considered to be Level 3 within the fair value hierarchy.
As discussed in "Note 3. Acquisitions, divestitures and other significant events", we recorded a
$23.2 million
loss in "Other operating items" in our Consolidated Statements of Operations during 2016 and a corresponding credit to our "Proved developed and undeveloped oil and natural gas properties" in our balance sheet related to the settlement of litigation with a joint venture partner in the Eagle Ford shale. The fair market value of the properties transferred pursuant to the settlement was determined using 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. The fair value measurements utilized included significant unobservable inputs that are considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows.
As discussed in "Note 2. Summary of significant accounting policies", we assess our unproved oil and natural gas properties for potential impairment due to an other than temporary trend that would negatively impact the fair value. During the year ended December 31, 2015, we impaired approximately
$88.1 million
of unproved properties to reduce the carrying value to the fair value. These impairment charges were transferred to the depletable portion of the full cost pool. We calculated the estimated fair value of our unproved properties based on the average cost per undeveloped acre or the discounted cash flow models from our internally generated oil and natural gas reserves as of December 31, 2015. The pricing utilized in the discounted cash flow models was based on NYMEX futures, adjusted for basis differentials. Our oil and natural gas properties were further discounted based on the classification of the underlying reserves and management's assessment of recoverability. The fair value measurements utilized included significant unobservable inputs that were considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows. The average cost per undeveloped acre was based on recent comparable market transactions in each region.
|
|
7.
|
Environmental regulation
|
Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations.
Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.
|
|
8.
|
Commitments and contingencies
|
The following table presents our future minimum obligations under our commercial commitments as of
December 31, 2016
. The commitments do not include those of our equity method investments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gathering and firm transportation services
|
|
Other fixed commitments
|
|
Drilling contracts
|
|
Operating leases and other
|
|
Total
|
2017
|
|
$
|
117,348
|
|
|
$
|
4,557
|
|
|
$
|
10,050
|
|
|
$
|
4,923
|
|
|
$
|
136,878
|
|
2018
|
|
113,628
|
|
|
3,222
|
|
|
—
|
|
|
3,808
|
|
|
120,658
|
|
2019
|
|
73,548
|
|
|
2,415
|
|
|
—
|
|
|
3,148
|
|
|
79,111
|
|
2020
|
|
45,403
|
|
|
1,949
|
|
|
—
|
|
|
1,538
|
|
|
48,890
|
|
2021
|
|
33,306
|
|
|
1,601
|
|
|
—
|
|
|
—
|
|
|
34,907
|
|
Thereafter
|
|
127,750
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
127,750
|
|
Total
|
|
$
|
510,983
|
|
|
$
|
13,744
|
|
|
$
|
10,050
|
|
|
$
|
13,417
|
|
|
$
|
548,194
|
|
Gathering and firm transportation services
We have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas and North Louisiana production. Gathering and firm transportation services presented in the tables within this footnote represent our gross commitments under these contracts, and a portion of these costs will be incurred by working interest and other owners. We report these costs as gathering and transportation expenses or as a reduction in total sales price received from the purchaser. In addition, our variable rate firm transportation and gathering agreements do not have a minimum volume commitment and are not included in the tables within this footnote. As such, our gathering and firm transportation services presented in the table above may not be representative of the amounts reported as gathering and transportation expenses in our Consolidated Financial Statements.
At
December 31, 2016
, our firm transportation and gathering agreements covered the following gross volumes of natural gas:
|
|
|
|
|
|
|
|
(in Bcf)
|
|
Firm transportation services
|
|
Gathering services
|
2017
|
|
269
|
|
|
110
|
|
2018
|
|
269
|
|
|
100
|
|
2019
|
|
269
|
|
|
—
|
|
2020
|
|
177
|
|
|
—
|
|
2021
|
|
146
|
|
|
—
|
|
Thereafter
|
|
560
|
|
|
—
|
|
Total
|
|
1,690
|
|
|
210
|
|
Natural gas sales and firm transportation contract litigation
During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) and Acadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Acadian is an indirect, wholly-owned subsidiary of EPD that owns and operates the Acadian natural gas pipeline system. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of $0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell 75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025. The fees described represent our gross commitments and a portion of these costs is allocated to working interest and other owners. The Acadian firm transportation agreement is accounted for as gathering and transportation expenses, and the Enterprise sales contract is accounted for as a reduction in the total sales price within revenues.
Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise and Acadian subsequently filed an action in Harris County, Texas, against us alleging that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the natural gas sales agreement, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian. We cannot currently estimate or predict the outcome of the litigation but we plan to vigorously defend our right to terminate the contracts and to seek the amounts owed to us for delivered natural gas.
We are no longer selling natural gas under the Enterprise sales contract or transporting natural gas under the Acadian firm transportation contract effective as of the termination date. The Company is accounting for these contracts in accordance with FASB ASC 450 ("ASC 450"),
Contingencies
, which states a contingency that might result in a gain should not be reflected until it is realized or realizable. There is a rebuttable presumption that a claim subject to litigation does not meet the criteria to be realized or realizable; therefore, the termination of these contracts will not be reflected in our financial results until the litigation is resolved. Upon resolution of the litigation, we will adjust the previously recognized amounts to reflect the outcome of the litigation. As of December 31, 2016, we recorded a
$6.4 million
receivable related to the net amounts owed by Enterprise prior to the termination of the contracts and an accrual of
$10.5 million
for costs subsequent to the termination of the contract in accordance with the guidance related to contingencies in ASC 450.
Other commitments
We lease our offices and certain equipment. Our rental expenses were approximately
$2.6 million
,
$3.4 million
and
$5.1 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively. We have also entered into drilling rig contracts primarily to develop our assets in the East Texas and North Louisiana regions. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties. These contracts are short-term in nature and are dependent on our planned drilling program.
Our other fixed commitments primarily consist of marketing contracts in which we are obligated to pay the buyer a fee if we fail to deliver minimum quantities of natural gas.
In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil and natural gas sold. We have reserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations.
We believe that we have properly reflected any potential exposure in our financial position when determined to be both probable and estimable. See further discussion of the litigation related to the Participation Agreement as part of "Item 1A. Risk Factors", "Item 3. Legal Proceedings" and "Item 7. Management's Discussion and Analysis".
|
|
9.
|
Employee benefit plans
|
We sponsor a 401(k) plan for our employees and matched
100%
of employee contributions during 2015 and 2014. Our matching program was suspended during 2016 in response to depressed oil and natural gas prices which have negatively impacted our business and operations. The Company reinstated its matching program effective January 1, 2017 in which it will match
100%
of employee contributions up to a maximum of
3%
of each employee's pay. Our matching contributions were
$5.2 million
and
$7.1 million
for the years ended December 31,
2015
and
2014
, respectively.
The following table presents the basic and diluted earnings (loss) per share computations for the years ended
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands, except per share data)
|
|
2016
|
|
2015
|
|
2014
|
Basic net income (loss) per common share:
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(225,258
|
)
|
|
$
|
(1,192,381
|
)
|
|
$
|
120,669
|
|
Weighted average common shares outstanding
|
|
279,287
|
|
|
273,621
|
|
|
268,258
|
|
Net income (loss) per basic common share
|
|
$
|
(0.81
|
)
|
|
$
|
(4.36
|
)
|
|
$
|
0.45
|
|
Diluted net income (loss) per common share:
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(225,258
|
)
|
|
$
|
(1,192,381
|
)
|
|
$
|
120,669
|
|
Weighted average common shares outstanding
|
|
279,287
|
|
|
273,621
|
|
|
268,258
|
|
Dilutive effect of:
|
|
|
|
|
|
|
Stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted shares and restricted share units
|
|
—
|
|
|
—
|
|
|
118
|
|
Warrants
|
|
—
|
|
|
—
|
|
|
—
|
|
Weighted average common shares and common share equivalents outstanding
|
|
279,287
|
|
|
273,621
|
|
|
268,376
|
|
Net income (loss) per diluted common share
|
|
$
|
(0.81
|
)
|
|
$
|
(4.36
|
)
|
|
$
|
0.45
|
|
The computation of diluted EPS excluded
76,463,063
,
39,544,192
and
14,316,409
antidilutive common share equivalents for the years ended
December 31, 2016
,
2015
and
2014
, respectively. Our antidilutive share equivalents during 2016 and 2015 included warrants issued to ESAS. See "Note 11. Equity-based compensation" for additional information on the warrants issued to ESAS. The issuance of warrants and potential for interest payments in the Company's common shares related to the 1.5 Lien Notes and 1.75 Lien Term Loans could materially change the number of common shares or potential common shares outstanding. See further discussion of the warrants and potential common shares to be issued in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans in "Note 18. Subsequent Events."
11.
Equity-based compensation
Stock options and awards
Description of plan
Our 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to
45,500,000
restricted shares, restricted share units and stock options. As of
December 31, 2016
and
2015
, there were
14,293,850
and
17,773,172
shares, respectively, available for issuance under the 2005 Incentive Plan. Option grants and restricted share grants count as
one
share and
1.74
shares, respectively, against the total number of shares available for grant. The holders of restricted shares, excluding restricted share units ("RSU") discussed below, have voting rights, and upon vesting, the right to receive all accrued and unpaid dividends.
Stock options
Our outstanding stock option expiration dates range from
5
to
10
years following the date of grant and have a weighted average remaining life of
3.3
years. Pursuant to the 2005 Incentive Plan,
25%
of the options vest immediately with an additional
25%
to vest on each of the next
three
anniversaries of the date of the grant.
The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan for the years ended December 31,
2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options
|
|
Weighted average exercise price per share
|
|
Weighted average remaining terms (in years)
|
|
Aggregate intrinsic value
|
|
|
Options outstanding at December 31, 2013
|
|
11,711,743
|
|
|
$
|
12.69
|
|
|
|
|
|
|
Granted
|
|
141,525
|
|
|
5.24
|
|
|
|
|
|
|
Forfeitures
|
|
(1,700,250
|
)
|
|
12.71
|
|
|
|
|
|
|
Exercised
|
|
(2,500
|
)
|
|
5.22
|
|
|
|
|
|
|
Options outstanding at December 31, 2014
|
|
10,150,518
|
|
|
12.58
|
|
|
|
|
|
|
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Forfeitures
|
|
(4,538,858
|
)
|
|
12.30
|
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Options outstanding at December 31, 2015
|
|
5,611,660
|
|
|
12.81
|
|
|
|
|
|
|
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Forfeitures
|
|
(3,230,734
|
)
|
|
12.86
|
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Options outstanding at December 31, 2016
|
|
2,380,926
|
|
|
$
|
12.74
|
|
|
3.3
|
|
$
|
—
|
|
|
Options exercisable at December 31, 2016
|
|
2,365,589
|
|
|
$
|
12.79
|
|
|
3.3
|
|
$
|
—
|
|
The weighted average fair value of stock options on the date of the grant during the year ended December 31,
2014
was
$2.23
.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The exercise price of the options is based on the fair market value of the common shares on the date of grant. No options were granted during 2016 or 2015. The following assumptions were used for the options included in the table above, for the year ended December 31:
|
|
|
|
|
|
2014
|
Expected life
|
|
7.5 years
|
Risk-free rate of return
|
|
2.25 - 2.61 %
|
Volatility
|
|
59.46 - 59.61 %
|
Dividend yield
|
|
3.36 - 4.34 %
|
Expected life was determined based on EXCO's exercise history. Risk-free rate of return is a rate of a similar term U.S. Treasury zero coupon bond. Volatility was determined based on the weighted average of historical volatility of our common shares. Dividend yield was determined based on EXCO's expected annual dividend and the market price of our common stock on the date of grant.
Service-based restricted share awards
Our service-based restricted share awards are valued at the closing price of our common shares on the date of grant and vest over a range of
one
to
five
years. A summary of our service-based restricted share activity for the years ended
December 31, 2016
,
2015
and
2014
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
|
Non-vested shares outstanding at December 31, 2013
|
|
1,928,314
|
|
|
$
|
9.26
|
|
|
Granted
|
|
1,339,782
|
|
|
5.20
|
|
|
Vested
|
|
(1,109,866
|
)
|
|
9.79
|
|
|
Forfeited
|
|
(280,301
|
)
|
|
6.89
|
|
|
Non-vested shares outstanding at December 31, 2014
|
|
1,877,929
|
|
|
$
|
6.40
|
|
|
Granted
|
|
4,414,470
|
|
|
1.05
|
|
|
Vested
|
|
(847,446
|
)
|
|
6.80
|
|
|
Forfeited
|
|
(903,383
|
)
|
|
3.17
|
|
|
Non-vested shares outstanding at December 31, 2015
|
|
4,541,570
|
|
|
$
|
1.77
|
|
|
Granted
|
|
1,487,309
|
|
|
1.22
|
|
|
Vested
|
|
(2,171,186
|
)
|
|
1.71
|
|
|
Forfeited
|
|
(1,670,073
|
)
|
|
2.02
|
|
|
Non-vested shares outstanding at December 31, 2016
|
|
2,187,620
|
|
|
$
|
1.27
|
|
Market-based restricted share awards
On August 13, 2013, EXCO’s officers were granted a market-based restricted share award with vesting dependent on the Company's common share price achieving certain price targets. There were
164,200
shares outstanding on December 31, 2016, including
82,100
shares that will be vested following any
30
consecutive trading days in which the company’s common stock equals or exceeds
$10.00
per share, and
82,100
shares will be vested following any
30
consecutive trading days in which the Company’s common shares equals or exceeds
$15.00
per share ("Target Price Awards"). The shares expire on August 13, 2018 and are subject to vesting provisions depending on when the target price attainment date occurs. No such awards were granted in 2016, 2015 or 2014 and no awards have vested to date.
During 2016 and 2014, we granted RSUs to our officers and certain employees that have vesting percentages between
0%
and
200%
depending on EXCO's total shareholder return in comparison to an identified peer group. Our market-based restricted share units are valued on the date of grant and vest over a range of three years, subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method.
The Company has discretion to convert certain vested awarded units, if any, into a cash payment equal to the fair market value of a share of common stock, multiplied by the number of vested units, or the number of whole shares of common stock equal to the number of vested units, if any. These RSUs met the criteria for equity classification per ASC 718, however we will assess the classification of these RSUs throughout their life, and if it becomes probable that the Company will settle the awards in cash, we will reclassify the award to a liability.
The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. The range of assumptions used in the Monte Carlo model for the RSUs granted in 2016 and 2014 are as follows:
|
|
|
|
|
|
Assumption
|
|
2016
|
|
2014
|
Risk-free rate of return
|
|
0.45 - 0.71 %
|
|
0.90 %
|
Volatility
|
|
119.83 %
|
|
48.73 %
|
Dividend yield
|
|
0.00 %
|
|
3.46 %
|
A summary of our market-based restricted share activity for the years ended
December 31, 2016
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target Price Awards
|
|
RSUs
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
|
|
|
|
Non-vested shares/units outstanding at December 31, 2015
|
|
290,200
|
|
|
$
|
6.36
|
|
|
546,878
|
|
|
$
|
7.33
|
|
Granted (1)
|
|
—
|
|
|
—
|
|
|
6,848,934
|
|
|
1.63
|
|
Vested
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Forfeited
|
|
(126,000
|
)
|
|
6.36
|
|
|
(2,335,440
|
)
|
|
2.46
|
|
Non-vested shares/units outstanding at December 31, 2016
|
|
164,200
|
|
|
$
|
6.36
|
|
|
5,060,372
|
|
|
$
|
1.85
|
|
|
|
(1)
|
RSUs granted reflect the number of units granted. The actual payout of the shares granted in 2016 may be between
0%
and
150%
of the RSUs granted. The Company has discretion to convert vested awards into a cash payment equal to the fair market value of a share of common stock, multiplied by the number of vested units, or the number of whole shares of common stock equal to the number of vested units, if any.
|
Liability-classified awards
During 2015, EXCO’s officers were granted
2,496,250
performance-based share units ("PSU") as a part of its equity compensation program. Each participant is eligible to vest in and receive a number of PSUs, ranging from
0%
to
200%
of the target number of PSUs granted, based on the attainment of total shareholder return goals on the period commencing on and including the date of grant and ending on the third anniversary of the grant date. Each PSU represents a non-equity unit with a conversion value equal to the fair market value of a share of EXCO’s common stock. Under the terms of the agreements, the Company is required to convert vested PSUs into a cash payment in an aggregate amount equal to the number of vested PSUs multiplied by the fair market value of a share of common stock as of the vesting date, less applicable withholdings and deductions, as soon as administratively practicable following the determination that the vesting conditions have been achieved.
A summary of the PSUs for the year ended
December 31, 2016
is as follows:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted average fair value per share
|
|
|
|
Non-vested units outstanding at December 31, 2015
|
|
2,115,000
|
|
|
$
|
2.39
|
|
Granted
|
|
—
|
|
|
—
|
|
Vested
|
|
—
|
|
|
—
|
|
Forfeited
|
|
(1,085,000
|
)
|
|
2.12
|
|
Non-vested units outstanding at December 31, 2016
|
|
1,030,000
|
|
|
$
|
1.66
|
|
The PSUs are considered liability-classified awards because of the cash-settlement feature. At December 31, 2016, we recorded a liability of
$0.4 million
related to the PSUs included in the "Asset retirement obligations and other long-term liabilities" line item on our Consolidated Balance Sheets. Compensation costs associated with the PSUs are re-measured each interim reporting period and an adjustment is recorded in the "General and administrative expenses" line item in our Consolidated Statements of Operations.
The fair values of the PSUs were determined using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the PSUs during 2016 and 2015 are as follows:
|
|
|
|
|
|
Assumption
|
|
2016
|
|
2015
|
Risk-free rate of return
|
|
0.72 - 1.02 %
|
|
0.85 - 1.18 %
|
Volatility
|
|
114.41 - 150.91 %
|
|
62.58 - 95.79 %
|
Dividend yield
|
|
0.00 %
|
|
0.00 %
|
Warrants
On September 8, 2015, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of
80,000,000
common shares. The warrants were issued as an additional performance incentive under the services and investment agreement which is described in more detail in "Note 13. Related party transactions". The table below lists the number of common shares issuable upon exercise of the warrants at each exercise price and the term of the warrants.
|
|
|
|
|
|
|
|
Tranche
|
|
Number of shares issuable
|
|
Exercise Price
|
|
Term
|
Tranche A
|
|
15,000,000
|
|
$2.75
|
|
April 30, 2019
|
Tranche B
|
|
20,000,000
|
|
$4.00
|
|
March 31, 2020
|
Tranche C
|
|
20,000,000
|
|
$7.00
|
|
March 31, 2021
|
Tranche D
|
|
25,000,000
|
|
$10.00
|
|
March 31, 2021
|
The warrants will vest on March 31, 2019 and their exercisability is subject to EXCO’s common share price achieving certain performance hurdles as compared to the peer group. If EXCO’s performance rank is in the bottom half of the peer group, then the warrants will be forfeited and void. The number of the exercisable shares under the warrants increases linearly from
32,000,000
to
80,000,000
as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then all
80,000,000
warrants will be exercisable. The performance measurement period began on March 31, 2015 and will end on March 31, 2019.
Prior to March 31, 2019, if EXCO terminates the agreement for any reason other than for cause (as defined in the agreement), or ESAS terminates the agreement for cause (as defined in the agreement), then all of the warrants will fully vest and become exercisable. Prior to March 31, 2019, if ESAS terminates the agreement for any reason other than for cause, or EXCO terminates the agreement for cause, then each of the warrants will be canceled and forfeited.
In accordance with ASC 718, the grant date of the warrants was established upon approval of EXCO’s shareholders and the closing of the services and investment agreement which occurred on September 8, 2015. The fair value of the warrants is dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group and is determined using a Monte Carlo model. The table below shows the aggregate estimated fair value of the warrants as of
December 31, 2016
:
|
|
|
|
|
|
|
|
Tranche
|
|
Number of shares issuable
|
|
Estimated fair value per warrant
|
|
Estimated fair value (in millions)
|
Tranche A
|
|
15,000,000
|
|
$0.45
|
|
$6.8
|
Tranche B
|
|
20,000,000
|
|
$0.52
|
|
10.4
|
Tranche C
|
|
20,000,000
|
|
$0.52
|
|
10.4
|
Tranche D
|
|
25,000,000
|
|
$0.48
|
|
12.0
|
|
|
|
|
|
|
$39.6
|
The fair values of the warrants were determined using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the warrants during 2016 and 2015 are as follows:
|
|
|
|
|
|
Assumption
|
|
2016
|
|
2015
|
Risk-free rate of return
|
|
0.69 - 1.76 %
|
|
1.05 - 1.80 %
|
Volatility
|
|
100.98 - 137.25 %
|
|
75.18 - 86.13 %
|
Dividend yield
|
|
0.00 %
|
|
0.00 %
|
Compensation costs
All of our stock options, restricted shares and PSUs are accounted for in accordance with ASC 718 and are classified as equity except for the PSUs. As required by ASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital.
Total share-based compensation to employees to be recognized on unvested options, restricted share awards and RSUs as of
December 31, 2016
was
$7.9 million
and will be recognized over a weighted average period of
1.8
years.
The measurement of the warrants is accounted for in accordance with ASC 505-50, which requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded in the statement of operations within equity-based compensation expense. For the years ended December 31, 2016 and 2015, we recognized equity-based compensation related to the warrants of
$11.3 million
and
$3.2 million
, respectively.
The following is a reconciliation of our compensation expense for the years ended
December 31, 2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
2014
|
Equity-based compensation expense (1)
|
|
$
|
14,778
|
|
|
$
|
7,198
|
|
|
$
|
4,962
|
|
Equity-based compensation capitalized
|
|
752
|
|
|
3,428
|
|
|
5,498
|
|
Total equity-based compensation (2)
|
|
$
|
15,530
|
|
|
$
|
10,626
|
|
|
$
|
10,460
|
|
|
|
(1)
|
Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for warrants issued to ESAS in 2015. Equity-based compensation expense also includes
$0.7 million
and
$0.5 million
of share-based compensation related to the Company's Management Incentive Plan payable in fully-vested restricted shares for the years ended December 31, 2016 and 2015, respectively.
|
|
|
(2)
|
Total equity-based compensation does not include compensation expense on liability-classified awards which was not significant in any period presented.
|
We did not recognize a tax benefit attributable to our equity-based compensation for the years ended December 31, 2016, 2015 and 2014.
The income tax provision attributable to our income (loss) before income taxes for the years ended December 31,
2016
,
2015
and
2014
, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
2014
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
—
|
|
|
—
|
|
|
—
|
|
Total current income tax (benefit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
|
$
|
(73,214
|
)
|
|
$
|
(414,834
|
)
|
|
$
|
45,797
|
|
State
|
|
(7,248
|
)
|
|
(45,009
|
)
|
|
18,960
|
|
Valuation allowance
|
|
83,264
|
|
|
459,843
|
|
|
(64,757
|
)
|
Total deferred income tax (benefit)
|
|
2,802
|
|
|
—
|
|
|
—
|
|
Total income tax (benefit)
|
|
$
|
2,802
|
|
|
$
|
—
|
|
|
$
|
—
|
|
We have net operating loss carryforwards ("NOLs") for United States income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between 2028 and 2036. As a result of the repurchase of a portion of our senior unsecured notes during 2015 and 2016, we had cancellation of debt income for tax purposes. We reduced our NOLs by the amount of cancellation of debt income of approximately
$125.8 million
and
$538.0 million
during 2016 and 2015, respectively. The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change based on the criteria in Section 382 of the Internal Revenue Code. See further information as part of "Item 1A. Risk Factors - Our ability to use net operating loss carryovers to reduce future tax payments may be limited."
NOLs and alternative minimum tax credits available for utilization as of
December 31, 2016
were approximately
$2.2 billion
and
$1.5 million
, respectively. We generated a net capital loss of approximately
$105.6 million
during the year ended December 31, 2014 as a result of the sale of our interest in Compass.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
December 31, 2015
|
Non-current deferred tax assets:
|
|
|
|
|
Net operating loss and AMT credits carryforwards
|
|
$
|
863,164
|
|
|
$
|
689,441
|
|
Capital loss carryforwards
|
|
40,356
|
|
|
40,356
|
|
Equity-based compensation
|
|
20,181
|
|
|
17,372
|
|
Oil and natural gas properties, gathering assets, and equipment
|
|
254,751
|
|
|
356,471
|
|
Debt restructuring
|
|
99,934
|
|
|
122,900
|
|
Goodwill
|
|
—
|
|
|
1,308
|
|
Derivative financial instruments
|
|
7,031
|
|
|
—
|
|
Investment in partnerships
|
|
82,069
|
|
|
76,099
|
|
Other
|
|
2,473
|
|
|
3,387
|
|
Total non-current deferred tax assets
|
|
1,369,959
|
|
|
1,307,334
|
|
Valuation allowance
|
|
(1,369,959
|
)
|
|
(1,286,695
|
)
|
Total non-current deferred tax assets
|
|
—
|
|
|
20,639
|
|
Non-current deferred tax liabilities:
|
|
|
|
|
Goodwill
|
|
$
|
(2,802
|
)
|
|
$
|
—
|
|
Derivative financial instruments
|
|
—
|
|
|
(20,639
|
)
|
Total non-current deferred tax liabilities
|
|
(2,802
|
)
|
|
(20,639
|
)
|
Net non-current deferred tax assets (liabilities)
|
|
$
|
(2,802
|
)
|
|
$
|
—
|
|
A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended
December 31, 2016
,
2015
and
2014
is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
2014
|
Federal income taxes (benefit) provision at statutory rate of 35%
|
|
$
|
(77,860
|
)
|
|
$
|
(417,333
|
)
|
|
$
|
42,234
|
|
Increases (reductions) resulting from:
|
|
|
|
|
|
|
Adjustments to the valuation allowance
|
|
83,264
|
|
|
459,843
|
|
|
(64,757
|
)
|
Non-deductible compensation
|
|
4,631
|
|
|
2,399
|
|
|
3,409
|
|
State taxes net of federal benefit
|
|
(7,248
|
)
|
|
(45,009
|
)
|
|
3,464
|
|
State tax rate change
|
|
—
|
|
|
—
|
|
|
15,496
|
|
Other
|
|
15
|
|
|
100
|
|
|
154
|
|
Total income tax provision
|
|
$
|
2,802
|
|
|
$
|
—
|
|
|
$
|
—
|
|
During the year ended December 31, 2016, we recognized deferred income tax expense of
$2.8 million
related to a deferred tax liability for tax deductible goodwill. During the year ended December 31, 2016, the book basis of goodwill exceeded the tax basis that caused the previous book and tax basis differences to change from a deferred tax asset to a deferred tax liability. The deferred tax liability related to goodwill is considered to have an indefinite life based on the nature of the underlying asset and cannot be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. However, the deferred income tax expense is not expected to result in cash payments of income taxes in the foreseeable future.
During years ended
2015
and
2014
, both federal and state income tax expense or tax benefit were reduced to
zero
by a corresponding increase or decrease to the valuation allowance previously recognized against net deferred tax assets. The net result was no income tax provision for years ended December 31,
2015
and
2014
.
We adopted the provisions of ASC 740-10
on January 1, 2007. As a result of the implementation of ASC 740-10, the Company did not recognize any liabilities for unrecognized tax benefits. As of December 31,
2016
,
2015
and
2014
, the Company's policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. The Company has not accrued any interest or penalties relating to unrecognized tax benefits in the consolidated financial statements.
We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax returns in various states. With few exceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2007.
|
|
13.
|
Related party transactions
|
OPCO
OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during the years ended
December 31, 2016
,
2015
or
2014
. OPCO may distribute any excess cash equally between us and Shell when its operating cash flows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the years ended
December 31, 2016
,
2015
and
2014
these transactions included the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
2014
|
Amounts received from OPCO
|
|
15,016
|
|
|
30,577
|
|
|
53,002
|
|
As of
December 31, 2016
and
2015
, the amounts owed under the service agreements were as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
December 31, 2015
|
Amounts due to EXCO (1)
|
|
$
|
618
|
|
|
$
|
1,733
|
|
Amounts due from EXCO (1)
|
|
13,624
|
|
|
10,410
|
|
|
|
(1)
|
Advances to OPCO are recorded in "Inventory and other" on our Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Consolidated Balance Sheets.
|
ESAS
On March 31, 2015, we entered into a
four
year services and investment agreement with ESAS. ESAS is owned by Bluescape Energy Recapitalization and Restructuring Fund III LP, which is directed by its general partner, Bluescape Energy Partners III GP LLC ("Bluescape"). As part of this agreement, ESAS provides us with certain strategic advisory services, including the development and execution of a strategic improvement plan. On September 8, 2015, we closed the services and investment agreement with ESAS and C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as Executive Chairman of the Board of Directors.
On September 8, 2015, ESAS completed the purchase of
5,882,353
common shares from EXCO, par value
$0.001
per share, at a price per share of
$1.70
, pursuant to the agreement. In addition, ESAS purchased additional
12,464,130
of common shares during the fourth quarter of 2015, completing its obligation to purchase at least
$13.5 million
of common shares through open market purchases. As of December 31, 2016, ESAS was the beneficial owner of approximately
6.6%
of our outstanding common shares.
As consideration for the services to be provided under the agreement, EXCO pays ESAS a monthly fee of
$300,000
and an annual incentive payment of up to
$2.4 million
per year that is based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group. The monthly fees were held in escrow until one year following the closing of the agreement and reported as "Restricted cash" on our Consolidated Balance Sheets.
If EXCO’s performance rank is below the 50th percentile of the peer group, then the incentive payment will be
zero
. The incentive payment increases linearly from
$1.0 million
to
$2.4 million
as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then the incentive payment will be
$2.4 million
.
For the years ended
December 31, 2016
and
2015
, these transactions included the following:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
Amounts paid to ESAS (1)
|
|
8,401
|
|
|
—
|
|
|
|
(1)
|
Amounts paid to ESAS in 2016 consisted of (i) the monthly fees including fees previously held in escrow and (ii) a
$2.4 million
annual incentive payment as a result of EXCO achieving a performance rank above the 75th percentile of the peer group.
|
As of
December 31, 2016
and
2015
, the amounts due to ESAS for the services performed under the services and investment agreements were as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2016
|
|
December 31, 2015
|
Amounts due to ESAS (1)
|
|
$
|
300
|
|
|
$
|
4,500
|
|
|
|
(1)
|
Amounts due to ESAS are recorded in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets. The amount at December 31, 2015 includes an accrual for the annual incentive payment of
$1.8 million
. We did not make an accrual for the annual incentive payment at December 31, 2016 as a result of EXCO's performance rank.
|
As an additional performance incentive under the services and investment agreement, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of
80,000,000
common shares. See "Note 11. Equity-based compensation" for further discussion of the warrants.
In the first quarter of 2016, ESAS entered into an agreement with an unaffiliated lender under the Exchange Term Loan, pursuant to which the lender made periodic payments to ESAS or received periodic payments from ESAS based on changes in the market value of the Exchange Term Loan, and the lender made periodic payments to ESAS based on the interest rate of the Exchange Term Loan. As of December 31, 2016, the agreement effectively provided ESAS with the economic consequences of ownership of approximately
$47.9 million
in principal amount of the Exchange Term Loan without direct ownership of, or consent rights with respect to, the Exchange Term Loan. In January 2016, ESAS irrevocably purchased and assumed all the rights and obligations from this unaffiliated lender and became a direct lender under a portion of the Exchange Term Loan. On
March 15, 2017
, ESAS exchanged its interests in the Exchange Term Loan for a like amount of the 1.75 Lien Term Loans and received a consent fee of
$1.6 million
in cash. Furthermore, ESAS is an investor of the 1.5 Lien Notes and holds
$70.0 million
in aggregate principal amount. In connection with the issuance of the 1.5 Lien Notes, ESAS received warrants representing the right to purchase an aggregate of
75,268,818
common shares at an exercise price equal to
$0.93
per share and a commitment fee of
$2.1 million
in cash. See "Note 18. Subsequent Events" for additional information.
As described above, ESAS is a wholly owned subsidiary of Bluescape, and C. John Wilder, the Executive Chairman of our Board of Directors, is Bluescape’s Executive Chairman. As Bluescape’s Executive Chairman, Mr. Wilder has the power to direct the affairs of Bluescape and, indirectly, ESAS, and may be deemed to share ESAS’s interest in the 1.5 Lien Notes, 1.75 Lien Term Loans and our common shares.
Fairfax
Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), the investment manager of Fairfax and certain affiliates thereof, was the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax were lenders under the Fairfax Term Loan. Samuel A. Mitchell, a member of our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. As an administrative agent of the Fairfax Term Loan, Fairfax received a one-time fee of
$6.0 million
from EXCO upon closing. In addition, certain affiliates of Fairfax were lenders under a portion of the Exchange Term Loan. As of December 31, 2016, affiliates of Fairfax were the record holders of approximately
$112.1 million
in principal amount of the Exchange Term Loan.
For the years ended December 31, 2016 and 2015, Fairfax received
$49.9 million
and
$6.9 million
, respectively, of interest payments under the Second Lien Term Loans. At December 31, 2016, Fairfax was the beneficial owner of approximately
9.9%
of our outstanding common shares. See “Note 5. Debt” and "Note 18. Subsequent Events" for additional information.
On
March 15, 2017
, Fairfax exchanged its interests in the Fairfax Term Loan and the Exchange Term Loan for the 1.75 Lien Term Loan and received warrants representing the right to purchase an aggregate of
19,412,035
common shares at an exercise price equal to
$0.01
per share. Furthermore, Fairfax is an investor of the 1.5 Lien Notes and holds
$151.0 million
in aggregate principal amount. In connection with the issuance of the 1.5 Lien Notes, Fairfax received warrants representing the
right to purchase an aggregate of
162,365,599
common shares at an exercise price equal to
$0.93
per share and additional warrants representing the right to purchase an aggregate of
6,471,433
common shares at an exercise price equal to
$0.01
per share.
Oaktree
Oaktree Capital Management, LP ("Oaktree"), is an investor of the 1.5 Lien Notes and holds
$39.5 million
in aggregate principal amount. In connection with the issuance of the 1.5 Lien Notes, Oaktree received warrants representing the right to purchase an aggregate of
42,473,119
common shares at an exercise price equal to
$0.93
per share and a commitment fee of
$1.2 million
in cash. B. James Ford, a member of our Board of Directors, serves as a Senior Adviser of Oaktree. At December 31, 2016, Oaktree was the beneficial owner of approximately
11.0%
of our outstanding common shares.
Rights offering
As discussed in "Note 14. Rights offering and other equity transactions", we entered into investment agreements and closed a related private placement of our common shares with certain affiliates of WL Ross & Co. LLC ("WL Ross") and Hamblin Watsa. Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer of WL Ross, and Samuel A. Mitchell, Managing Director of Hamblin Watsa, both of whom served on EXCO's Board of Directors during 2016. On
February 27
, 2017
, Mr. Ross resigned from our Board of Directors and each of its committees, upon the confirmation of his appointment as the U.S. Secretary of Commerce. Mr. Ross was replaced by Stephen J. Toy, Senior Managing Director and Co-Head of WL Ross.
|
|
14.
|
Rights Offering and other equity transactions
|
On December 19, 2013, the Company granted subscription rights to holders of common shares which entitled the holder to purchase
0.25
of a share of our common stock for each share of common stock owned by such holders. Each subscription right entitled the holder to a basic subscription right and an over-subscription privilege. The basic subscription right entitled the holder to purchase
0.25
of a share of the Company’s common shares at a subscription price equal to
$5.00
per share of common stock. The over-subscription privilege entitled the holders who exercised their basic subscription rights in full (including in respect of subscription rights purchased from others) to purchase any or all shares of our common shares that other rights holders did not purchase through the purchase of their basic subscription rights at a subscription price equal to
$5.00
per share of our common shares. The subscription rights expired if they were not exercised by January 9, 2014.
The Company entered into two investment agreements ("Investment Agreements") in connection with the rights offering, each dated as of December 17, 2013, one with certain affiliates of WL Ross and one with Hamblin Watsa pursuant to which, subject to the terms and conditions thereof, each of them has severally agreed to subscribe for and purchase, in a private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege subject to pro rata allocation among the subscription rights holders who have elected to exercise their over-subscription privilege.
The rights offering and related transactions under the Investment Agreements closed on January 17, 2014 ("Rights Offering") which resulted in the issuance of
54,574,734
shares for proceeds of
$272.9 million
. We used the proceeds to pay indebtedness under the EXCO Resources Credit Agreement. WL Ross and Hamblin Watsa purchased
19,599,973
and
6,726,712
shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege.
Preferred Shares
We canceled all classes of our preferred shares in 2014. We have
10,000,000
preferred shares authorized with
no
preferred shares issued and outstanding. Our issued and outstanding shares of capital stock consist solely of common shares.
|
|
15.
|
Condensed consolidating financial statements
|
As of
December 31, 2016
, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement, the indentures governing the 2018 Notes and 2022 Notes and the agreements governing the Second Lien Term Loans. On
March 15, 2017
, we closed the 1.5 Lien Notes and 1.75 Lien Term Loan which are guaranteed by the same subsidiaries as the EXCO Resources Credit Agreement, Second Lien Term Loans, 2018 Notes and the 2022 Notes. All of our unrestricted subsidiaries under the Second 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 2018 Notes, 2022 Notes, the Second Lien Term Loans, and subsequently the 1.5 Lien Notes and
1.75 Lien Term Loans, 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.
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.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
24,610
|
|
|
$
|
(15,542
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,068
|
|
Restricted cash
|
|
—
|
|
|
11,150
|
|
|
—
|
|
|
—
|
|
|
11,150
|
|
Other current assets
|
|
6,463
|
|
|
83,936
|
|
|
—
|
|
|
—
|
|
|
90,399
|
|
Total current assets
|
|
31,073
|
|
|
79,544
|
|
|
—
|
|
|
—
|
|
|
110,617
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
24,365
|
|
|
—
|
|
|
24,365
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
97,080
|
|
|
—
|
|
|
—
|
|
|
97,080
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
331,823
|
|
|
2,608,100
|
|
|
—
|
|
|
—
|
|
|
2,939,923
|
|
Accumulated depletion
|
|
(330,776
|
)
|
|
(2,371,469
|
)
|
|
—
|
|
|
—
|
|
|
(2,702,245
|
)
|
Oil and natural gas properties, net
|
|
1,047
|
|
|
333,711
|
|
|
—
|
|
|
—
|
|
|
334,758
|
|
Other property and equipment, net
|
|
568
|
|
|
23,093
|
|
|
—
|
|
|
—
|
|
|
23,661
|
|
Investments in and advances to affiliates, net
|
|
430,168
|
|
|
—
|
|
|
—
|
|
|
(430,168
|
)
|
|
—
|
|
Deferred financing costs, net
|
|
4,376
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,376
|
|
Derivative financial instruments
|
|
482
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
482
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
Total assets
|
|
$
|
481,007
|
|
|
$
|
586,210
|
|
|
$
|
24,365
|
|
|
$
|
(430,168
|
)
|
|
$
|
661,414
|
|
Liabilities and shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
90,671
|
|
|
$
|
167,692
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
258,363
|
|
Long-term debt
|
|
1,258,538
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,258,538
|
|
Other long-term liabilities
|
|
3,704
|
|
|
12,715
|
|
|
—
|
|
|
—
|
|
|
16,419
|
|
Payable to parent
|
|
—
|
|
|
2,337,585
|
|
|
—
|
|
|
(2,337,585
|
)
|
|
—
|
|
Total shareholders' equity
|
|
(871,906
|
)
|
|
(1,931,782
|
)
|
|
24,365
|
|
|
1,907,417
|
|
|
(871,906
|
)
|
Total liabilities and shareholders' equity
|
|
$
|
481,007
|
|
|
$
|
586,210
|
|
|
$
|
24,365
|
|
|
$
|
(430,168
|
)
|
|
$
|
661,414
|
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
34,296
|
|
|
$
|
(22,049
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12,247
|
|
Restricted cash
|
|
2,100
|
|
|
19,120
|
|
|
—
|
|
|
—
|
|
|
21,220
|
|
Other current assets
|
|
51,133
|
|
|
65,201
|
|
|
—
|
|
|
—
|
|
|
116,334
|
|
Total current assets
|
|
87,529
|
|
|
62,272
|
|
|
—
|
|
|
—
|
|
|
149,801
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
40,797
|
|
|
—
|
|
|
40,797
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
115,377
|
|
|
—
|
|
|
—
|
|
|
115,377
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
330,775
|
|
|
2,739,655
|
|
|
—
|
|
|
—
|
|
|
3,070,430
|
|
Accumulated depletion
|
|
(330,775
|
)
|
|
(2,296,988
|
)
|
|
—
|
|
|
—
|
|
|
(2,627,763
|
)
|
Oil and natural gas properties, net
|
|
—
|
|
|
558,044
|
|
|
—
|
|
|
—
|
|
|
558,044
|
|
Other property and equipment, net
|
|
749
|
|
|
27,063
|
|
|
—
|
|
|
—
|
|
|
27,812
|
|
Investments in and advances to affiliates, net
|
|
616,940
|
|
|
—
|
|
|
—
|
|
|
(616,940
|
)
|
|
—
|
|
Deferred financing costs, net
|
|
8,408
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,408
|
|
Derivative financial instruments
|
|
6,109
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,109
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
Total assets
|
|
$
|
733,028
|
|
|
$
|
797,241
|
|
|
$
|
40,797
|
|
|
$
|
(616,940
|
)
|
|
$
|
954,126
|
|
Liabilities and shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
74,472
|
|
|
$
|
178,447
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
252,919
|
|
Long-term debt
|
|
1,320,279
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,320,279
|
|
Other long-term liabilities
|
|
600
|
|
|
42,651
|
|
|
—
|
|
|
—
|
|
|
43,251
|
|
Payable to parent
|
|
—
|
|
|
2,276,594
|
|
|
—
|
|
|
(2,276,594
|
)
|
|
—
|
|
Total shareholders' equity
|
|
(662,323
|
)
|
|
(1,700,451
|
)
|
|
40,797
|
|
|
1,659,654
|
|
|
(662,323
|
)
|
Total liabilities and shareholders' equity
|
|
$
|
733,028
|
|
|
$
|
797,241
|
|
|
$
|
40,797
|
|
|
$
|
(616,940
|
)
|
|
$
|
954,126
|
|
|
|
|
|
|
|
|
|
|
|
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
248,649
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
248,649
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
22,352
|
|
|
—
|
|
|
—
|
|
|
22,352
|
|
Total revenues
|
|
—
|
|
|
271,001
|
|
|
—
|
|
|
—
|
|
|
271,001
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
4
|
|
|
49,985
|
|
|
—
|
|
|
—
|
|
|
49,989
|
|
Gathering and transportation
|
|
—
|
|
|
106,460
|
|
|
—
|
|
|
—
|
|
|
106,460
|
|
Purchased natural gas
|
|
—
|
|
|
23,557
|
|
|
—
|
|
|
—
|
|
|
23,557
|
|
Depletion, depreciation and amortization
|
|
381
|
|
|
75,601
|
|
|
—
|
|
|
—
|
|
|
75,982
|
|
Impairment of oil and natural gas properties
|
|
838
|
|
|
159,975
|
|
|
—
|
|
|
—
|
|
|
160,813
|
|
Accretion of discount on asset retirement obligations
|
|
—
|
|
|
2,210
|
|
|
—
|
|
|
—
|
|
|
2,210
|
|
General and administrative
|
|
(11,254
|
)
|
|
59,954
|
|
|
—
|
|
|
—
|
|
|
48,700
|
|
Other operating items
|
|
(385
|
)
|
|
24,624
|
|
|
—
|
|
|
—
|
|
|
24,239
|
|
Total costs and expenses
|
|
(10,416
|
)
|
|
502,366
|
|
|
—
|
|
|
—
|
|
|
491,950
|
|
Operating income (loss)
|
|
10,416
|
|
|
(231,365
|
)
|
|
—
|
|
|
—
|
|
|
(220,949
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(70,438
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(70,438
|
)
|
Loss on derivative financial instruments
|
|
(34,137
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,137
|
)
|
Gain on extinguishment of debt
|
|
119,457
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
119,457
|
|
Other income
|
|
9
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
43
|
|
Equity loss
|
|
—
|
|
|
—
|
|
|
(16,432
|
)
|
|
—
|
|
|
(16,432
|
)
|
Net loss from consolidated subsidiaries
|
|
(247,763
|
)
|
|
—
|
|
|
—
|
|
|
247,763
|
|
|
—
|
|
Total other income (expense)
|
|
(232,872
|
)
|
|
34
|
|
|
(16,432
|
)
|
|
247,763
|
|
|
(1,507
|
)
|
Loss before income taxes
|
|
(222,456
|
)
|
|
(231,331
|
)
|
|
(16,432
|
)
|
|
247,763
|
|
|
(222,456
|
)
|
Income tax expense
|
|
2,802
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,802
|
|
Net loss
|
|
$
|
(225,258
|
)
|
|
$
|
(231,331
|
)
|
|
$
|
(16,432
|
)
|
|
$
|
247,763
|
|
|
$
|
(225,258
|
)
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
4
|
|
|
$
|
329,254
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
329,258
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
26,442
|
|
|
—
|
|
|
—
|
|
|
26,442
|
|
Total revenues
|
|
4
|
|
|
355,696
|
|
|
—
|
|
|
—
|
|
|
355,700
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
37
|
|
|
76,496
|
|
|
—
|
|
|
—
|
|
|
76,533
|
|
Gathering and transportation
|
|
—
|
|
|
99,321
|
|
|
—
|
|
|
—
|
|
|
99,321
|
|
Purchased natural gas
|
|
—
|
|
|
27,369
|
|
|
—
|
|
|
—
|
|
|
27,369
|
|
Depletion, depreciation and amortization
|
|
943
|
|
|
214,483
|
|
|
—
|
|
|
—
|
|
|
215,426
|
|
Impairment of oil and natural gas properties
|
|
9,316
|
|
|
1,206,054
|
|
|
—
|
|
|
—
|
|
|
1,215,370
|
|
Accretion of discount on asset retirement obligations
|
|
4
|
|
|
2,273
|
|
|
—
|
|
|
—
|
|
|
2,277
|
|
General and administrative
|
|
(4,313
|
)
|
|
63,131
|
|
|
—
|
|
|
—
|
|
|
58,818
|
|
Other operating items
|
|
1,646
|
|
|
(1,185
|
)
|
|
—
|
|
|
—
|
|
|
461
|
|
Total costs and expenses
|
|
7,633
|
|
|
1,687,942
|
|
|
—
|
|
|
—
|
|
|
1,695,575
|
|
Operating loss
|
|
(7,629
|
)
|
|
(1,332,246
|
)
|
|
—
|
|
|
—
|
|
|
(1,339,875
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(106,082
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(106,082
|
)
|
Gain on derivative financial instruments
|
|
75,869
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75,869
|
|
Gain on restructuring and extinguishment of debt
|
|
193,276
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
193,276
|
|
Other income
|
|
87
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
122
|
|
Equity loss
|
|
—
|
|
|
—
|
|
|
(15,691
|
)
|
|
—
|
|
|
(15,691
|
)
|
Net loss from consolidated subsidiaries
|
|
(1,347,902
|
)
|
|
—
|
|
|
—
|
|
|
1,347,902
|
|
|
—
|
|
Total other income (expense)
|
|
(1,184,752
|
)
|
|
35
|
|
|
(15,691
|
)
|
|
1,347,902
|
|
|
147,494
|
|
Loss before income taxes
|
|
(1,192,381
|
)
|
|
(1,332,211
|
)
|
|
(15,691
|
)
|
|
1,347,902
|
|
|
(1,192,381
|
)
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net loss
|
|
$
|
(1,192,381
|
)
|
|
$
|
(1,332,211
|
)
|
|
$
|
(15,691
|
)
|
|
$
|
1,347,902
|
|
|
$
|
(1,192,381
|
)
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
3,649
|
|
|
$
|
615,604
|
|
|
$
|
41,731
|
|
|
$
|
—
|
|
|
$
|
660,984
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
34,933
|
|
|
—
|
|
|
—
|
|
|
34,933
|
|
Total revenues
|
|
3,649
|
|
|
650,537
|
|
|
41,731
|
|
|
—
|
|
|
695,917
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
394
|
|
|
77,334
|
|
|
16,598
|
|
|
—
|
|
|
94,326
|
|
Gathering and transportation
|
|
—
|
|
|
97,784
|
|
|
3,790
|
|
|
—
|
|
|
101,574
|
|
Purchased natural gas
|
|
—
|
|
|
35,648
|
|
|
—
|
|
|
—
|
|
|
35,648
|
|
Depletion, depreciation and amortization
|
|
3,174
|
|
|
244,761
|
|
|
15,634
|
|
|
—
|
|
|
263,569
|
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Accretion of discount on asset retirement obligations
|
|
16
|
|
|
2,107
|
|
|
567
|
|
|
—
|
|
|
2,690
|
|
General and administrative
|
|
(3,342
|
)
|
|
66,686
|
|
|
2,576
|
|
|
—
|
|
|
65,920
|
|
Other operating items
|
|
(134
|
)
|
|
5,459
|
|
|
(10
|
)
|
|
—
|
|
|
5,315
|
|
Total costs and expenses
|
|
108
|
|
|
529,779
|
|
|
39,155
|
|
|
—
|
|
|
569,042
|
|
Operating income
|
|
3,541
|
|
|
120,758
|
|
|
2,576
|
|
|
—
|
|
|
126,875
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(92,049
|
)
|
|
—
|
|
|
(2,235
|
)
|
|
—
|
|
|
(94,284
|
)
|
Gain on derivative financial instruments
|
|
87,565
|
|
|
—
|
|
|
100
|
|
|
—
|
|
|
87,665
|
|
Other income
|
|
226
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
241
|
|
Equity income
|
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
|
172
|
|
Net earnings from consolidated subsidiaries
|
|
121,386
|
|
|
—
|
|
|
—
|
|
|
(121,386
|
)
|
|
—
|
|
Total other income (expense)
|
|
117,128
|
|
|
—
|
|
|
(1,948
|
)
|
|
(121,386
|
)
|
|
(6,206
|
)
|
Income before income taxes
|
|
120,669
|
|
|
120,758
|
|
|
628
|
|
|
(121,386
|
)
|
|
120,669
|
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income
|
|
$
|
120,669
|
|
|
$
|
120,758
|
|
|
$
|
628
|
|
|
$
|
(121,386
|
)
|
|
$
|
120,669
|
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
572
|
|
|
$
|
(986
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(414
|
)
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(1,521
|
)
|
|
(78,904
|
)
|
|
—
|
|
|
—
|
|
|
(80,425
|
)
|
Proceeds from disposition of property and equipment
|
|
10
|
|
|
14,339
|
|
|
—
|
|
|
—
|
|
|
14,349
|
|
Restricted cash
|
|
—
|
|
|
7,970
|
|
|
—
|
|
|
—
|
|
|
7,970
|
|
Net changes in advances to joint ventures
|
|
—
|
|
|
3,097
|
|
|
—
|
|
|
—
|
|
|
3,097
|
|
Advances/investments with affiliates
|
|
(60,991
|
)
|
|
60,991
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) investing activities
|
|
(62,502
|
)
|
|
7,493
|
|
|
—
|
|
|
—
|
|
|
(55,009
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreements
|
|
404,897
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
404,897
|
|
Repayments under credit agreements
|
|
(243,797
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(243,797
|
)
|
Repurchases of senior unsecured notes
|
|
(53,298
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(53,298
|
)
|
Payments on Exchange Term Loan
|
|
(50,695
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50,695
|
)
|
Payments of common share dividends
|
|
(91
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(91
|
)
|
Deferred financing costs and other
|
|
(4,772
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,772
|
)
|
Net cash provided by financing activities
|
|
52,244
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52,244
|
|
Net increase (decrease) in cash
|
|
(9,686
|
)
|
|
6,507
|
|
|
—
|
|
|
—
|
|
|
(3,179
|
)
|
Cash at beginning of period
|
|
34,296
|
|
|
(22,049
|
)
|
|
—
|
|
|
—
|
|
|
12,247
|
|
Cash at end of period
|
|
$
|
24,610
|
|
|
$
|
(15,542
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,068
|
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
34,532
|
|
|
$
|
99,495
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
134,027
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(2,601
|
)
|
|
(322,597
|
)
|
|
—
|
|
|
—
|
|
|
(325,198
|
)
|
Proceeds from disposition of property and equipment
|
|
686
|
|
|
6,711
|
|
|
—
|
|
|
—
|
|
|
7,397
|
|
Restricted cash
|
|
—
|
|
|
4,850
|
|
|
—
|
|
|
—
|
|
|
4,850
|
|
Net changes in advances to joint ventures
|
|
—
|
|
|
10,663
|
|
|
—
|
|
|
—
|
|
|
10,663
|
|
Equity investments and other
|
|
—
|
|
|
1,455
|
|
|
—
|
|
|
—
|
|
|
1,455
|
|
Advances/investments with affiliates
|
|
(217,906
|
)
|
|
217,906
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net cash used in investing activities
|
|
(219,821
|
)
|
|
(81,012
|
)
|
|
—
|
|
|
—
|
|
|
(300,833
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreements
|
|
165,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
165,000
|
|
Repayments under credit agreements
|
|
(300,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(300,000
|
)
|
Proceeds received from issuance of Fairfax Term Loan
|
|
300,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
300,000
|
|
Repurchases of senior unsecured notes
|
|
(12,008
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12,008
|
)
|
Payment on Exchange Term Loan
|
|
(8,827
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,827
|
)
|
Proceeds from issuance of common shares, net
|
|
9,693
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,693
|
|
Payments of common share dividends
|
|
(164
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(164
|
)
|
Deferred financing costs and other
|
|
(20,946
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20,946
|
)
|
Net cash used in financing activities
|
|
132,748
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
132,748
|
|
Net increase (decrease) in cash
|
|
(52,541
|
)
|
|
18,483
|
|
|
—
|
|
|
—
|
|
|
(34,058
|
)
|
Cash at beginning of period
|
|
86,837
|
|
|
(40,532
|
)
|
|
—
|
|
|
—
|
|
|
46,305
|
|
Cash at end of period
|
|
$
|
34,296
|
|
|
$
|
(22,049
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12,247
|
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-guarantor subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(84,067
|
)
|
|
$
|
428,029
|
|
|
$
|
18,131
|
|
|
$
|
—
|
|
|
$
|
362,093
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment
|
|
(2,531
|
)
|
|
(395,974
|
)
|
|
(4,061
|
)
|
|
—
|
|
|
(402,566
|
)
|
Proceeds from disposition of property and equipment
|
|
99,612
|
|
|
95,594
|
|
|
(7,551
|
)
|
|
—
|
|
|
187,655
|
|
Restricted cash
|
|
—
|
|
|
(3,400
|
)
|
|
—
|
|
|
—
|
|
|
(3,400
|
)
|
Net changes in advances to joint ventures
|
|
—
|
|
|
(5,026
|
)
|
|
—
|
|
|
—
|
|
|
(5,026
|
)
|
Distributions from Compass
|
|
5,856
|
|
|
—
|
|
|
—
|
|
|
(5,856
|
)
|
|
—
|
|
Equity investments and other
|
|
—
|
|
|
1,749
|
|
|
—
|
|
|
—
|
|
|
1,749
|
|
Advances/investments with affiliates
|
|
125,612
|
|
|
(125,612
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) investing activities
|
|
228,549
|
|
|
(432,669
|
)
|
|
(11,612
|
)
|
|
(5,856
|
)
|
|
(221,588
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under the credit agreements
|
|
100,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100,000
|
|
Repayments under the credit agreements
|
|
(959,874
|
)
|
|
—
|
|
|
(5,096
|
)
|
|
—
|
|
|
(964,970
|
)
|
Proceeds received from issuance of 2022 Notes
|
|
500,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
500,000
|
|
Proceeds from issuance of common shares, net
|
|
271,773
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
271,773
|
|
Payments of common share dividends
|
|
(41,060
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41,060
|
)
|
Compass cash distribution
|
|
—
|
|
|
—
|
|
|
(5,856
|
)
|
|
5,856
|
|
|
—
|
|
Deferred financing costs and other
|
|
(10,324
|
)
|
|
—
|
|
|
(102
|
)
|
|
—
|
|
|
(10,426
|
)
|
Net cash used in financing activities
|
|
(139,485
|
)
|
|
—
|
|
|
(11,054
|
)
|
|
5,856
|
|
|
(144,683
|
)
|
Net increase (decrease) in cash
|
|
4,997
|
|
|
(4,640
|
)
|
|
(4,535
|
)
|
|
—
|
|
|
(4,178
|
)
|
Cash at beginning of period
|
|
81,840
|
|
|
(35,892
|
)
|
|
4,535
|
|
|
—
|
|
|
50,483
|
|
Cash at end of period
|
|
$
|
86,837
|
|
|
$
|
(40,532
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46,305
|
|
|
|
16.
|
Quarterly financial data (unaudited)
|
The following are summarized quarterly financial data for the years ended
December 31, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
(in thousands, except per share amounts)
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
2016
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
56,090
|
|
|
$
|
58,791
|
|
|
$
|
77,186
|
|
|
$
|
78,934
|
|
Operating income (loss) (1)
|
|
(164,698
|
)
|
|
(72,997
|
)
|
|
4,142
|
|
|
12,604
|
|
Net income (loss) (2)
|
|
$
|
(130,148
|
)
|
|
$
|
(111,347
|
)
|
|
$
|
50,936
|
|
|
$
|
(34,699
|
)
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(0.47
|
)
|
|
$
|
(0.40
|
)
|
|
$
|
0.18
|
|
|
$
|
(0.12
|
)
|
Weighted average shares
|
|
278,357
|
|
|
278,783
|
|
|
279,873
|
|
|
280,119
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(0.47
|
)
|
|
$
|
(0.40
|
)
|
|
$
|
0.18
|
|
|
$
|
(0.12
|
)
|
Weighted average shares
|
|
278,357
|
|
|
278,783
|
|
|
281,045
|
|
|
280,119
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
94,038
|
|
|
$
|
100,604
|
|
|
$
|
90,517
|
|
|
$
|
70,541
|
|
Operating loss (3)
|
|
(313,618
|
)
|
|
(421,465
|
)
|
|
(363,975
|
)
|
|
(240,817
|
)
|
Net loss (4)
|
|
$
|
(318,112
|
)
|
|
$
|
(454,155
|
)
|
|
$
|
(354,519
|
)
|
|
$
|
(65,595
|
)
|
Basic loss per share:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(1.17
|
)
|
|
$
|
(1.67
|
)
|
|
$
|
(1.30
|
)
|
|
$
|
(0.24
|
)
|
Weighted average shares
|
|
271,522
|
|
|
271,549
|
|
|
273,348
|
|
|
277,995
|
|
Diluted loss per share:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(1.17
|
)
|
|
$
|
(1.67
|
)
|
|
$
|
(1.30
|
)
|
|
$
|
(0.24
|
)
|
Weighted average shares
|
|
271,522
|
|
|
271,549
|
|
|
273,348
|
|
|
277,995
|
|
|
|
(1)
|
Operating loss for the first and second quarter of 2016 includes
$134.6 million
and
$26.2 million
, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
|
|
|
(2)
|
Net income (loss) for the first, second and third quarter of 2016 includes
$45.1 million
,
$16.8 million
and
$57.4 million
net gains on extinguishment of debt. See "Note 5. Debt" for further discussion.
|
|
|
(3)
|
Operating loss for the first, second, third and fourth quarter of 2015 includes
$276.3 million
,
$394.3 million
,
$339.4 million
and
$205.3 million
, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
|
|
|
(4)
|
Net loss for the fourth quarter of 2015 includes a
$193.3 million
net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.
|
|
|
17.
|
Supplemental information relating to oil and natural gas producing activities (unaudited)
|
The following supplemental information relating to our oil and natural gas producing activities for the years ended
December 31, 2016
,
2015
and
2014
is presented in accordance with ASC 932,
Extractive Activities, Oil and Gas.
Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Amount
|
2016:
|
|
|
Proved property acquisition costs
|
|
$
|
638
|
|
Unproved property acquisition costs
|
|
393
|
|
Total property acquisition costs
|
|
1,031
|
|
Development
|
|
62,328
|
|
Exploration costs
|
|
—
|
|
Lease acquisitions and other
|
|
760
|
|
Capitalized asset retirement costs
|
|
—
|
|
Depletion per Boe
|
|
$
|
4.28
|
|
Depletion per Mcfe
|
|
$
|
0.71
|
|
2015:
|
|
|
Proved property acquisition costs
|
|
$
|
7,608
|
|
Unproved property acquisition costs
|
|
—
|
|
Total property acquisition costs
|
|
7,608
|
|
Development
|
|
215,239
|
|
Exploration costs (1)
|
|
13,306
|
|
Lease acquisitions and other
|
|
13,017
|
|
Capitalized asset retirement costs
|
|
881
|
|
Depletion per Boe
|
|
$
|
10.32
|
|
Depletion per Mcfe
|
|
$
|
1.72
|
|
2014:
|
|
|
Proved property acquisition costs
|
|
$
|
10,562
|
|
Unproved property acquisition costs
|
|
—
|
|
Total property acquisition costs
|
|
10,562
|
|
Development
|
|
354,199
|
|
Exploration costs (2)
|
|
5,906
|
|
Lease acquisitions and other
|
|
9,681
|
|
Capitalized asset retirement costs
|
|
576
|
|
Depletion per Boe
|
|
$
|
11.42
|
|
Depletion per Mcfe
|
|
$
|
1.90
|
|
|
|
(1)
|
Exploration costs in 2015 primarily relate to the wells drilled in the Buda formation in South Texas.
|
|
|
(2)
|
Exploration costs in 2014 include
$5.9 million
in the Bossier shale in North Louisiana.
|
We retain independent engineering firms to prepare or audit annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls)
|
|
Natural
Gas
(Mmcf)
|
|
Mmcfe (10)
|
December 31, 2013
|
|
15,378
|
|
|
1,031,977
|
|
|
1,124,245
|
|
Purchase of reserves in place (1)
|
|
—
|
|
|
7,316
|
|
|
7,316
|
|
Discoveries and extensions (2)
|
|
4,164
|
|
|
70,544
|
|
|
95,528
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
Changes in price
|
|
45
|
|
|
168,064
|
|
|
168,334
|
|
Other factors (3)
|
|
1,737
|
|
|
120,802
|
|
|
131,224
|
|
Sales of reserves in place (4)
|
|
(1,401
|
)
|
|
(118,705
|
)
|
|
(127,111
|
)
|
Production
|
|
(2,236
|
)
|
|
(122,324
|
)
|
|
(135,740
|
)
|
December 31, 2014
|
|
17,687
|
|
|
1,157,674
|
|
|
1,263,796
|
|
Purchase of reserves in place (5)
|
|
459
|
|
|
122
|
|
|
2,876
|
|
Discoveries and extensions (6)
|
|
7,602
|
|
|
152,473
|
|
|
198,085
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
Changes in price
|
|
(2,821
|
)
|
|
(598,865
|
)
|
|
(615,791
|
)
|
Other factors (7)
|
|
(145
|
)
|
|
184,641
|
|
|
183,771
|
|
Sales of reserves in place
|
|
(1
|
)
|
|
(1,445
|
)
|
|
(1,451
|
)
|
Production
|
|
(2,342
|
)
|
|
(109,926
|
)
|
|
(123,978
|
)
|
December 31, 2015
|
|
20,439
|
|
|
784,674
|
|
|
907,308
|
|
Purchase of reserves in place
|
|
—
|
|
|
552
|
|
|
552
|
|
Discoveries and extensions (8)
|
|
—
|
|
|
16,381
|
|
|
16,381
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
Changes in price
|
|
(2,061
|
)
|
|
(55,748
|
)
|
|
(68,114
|
)
|
Other factors (9)
|
|
(5,165
|
)
|
|
(208,714
|
)
|
|
(239,704
|
)
|
Sales of reserves in place
|
|
(1,276
|
)
|
|
(27,597
|
)
|
|
(35,253
|
)
|
Production
|
|
(1,769
|
)
|
|
(93,829
|
)
|
|
(104,443
|
)
|
December 31, 2016
|
|
10,168
|
|
|
415,719
|
|
|
476,727
|
|
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls)
|
|
Natural
Gas
(Mmcf)
|
|
Mmcfe
|
Proved developed:
|
|
|
|
|
|
|
December 31, 2016
|
|
10,168
|
|
|
415,719
|
|
|
476,727
|
|
December 31, 2015
|
|
12,056
|
|
|
364,932
|
|
|
437,268
|
|
December 31, 2014
|
|
14,429
|
|
|
504,636
|
|
|
591,210
|
|
Proved undeveloped:
|
|
|
|
|
|
|
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2015
|
|
8,383
|
|
|
419,742
|
|
|
470,040
|
|
December 31, 2014
|
|
3,258
|
|
|
653,038
|
|
|
672,586
|
|
|
|
(1)
|
Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas.
|
|
|
(2)
|
New discoveries and extensions in 2014 included
48.7
Bcfe in the Haynesville shale,
26.1
Bcfe in the Eagle Ford Shale and
19.7
Bcfe in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas.
|
|
|
(3)
|
Total revisions due to Other factors include upward revisions of approximately
67.1
Bcfe in the Shelby area, approximately
45.9
Bcfe in the Appalachia region, and approximately
5.8
Bcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
|
|
|
(4)
|
Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
|
|
|
(5)
|
Purchases of reserves in place include the acquisition of certain proved developed producing properties in the Eagle Ford shale in connection with the Participation Agreement.
|
|
|
(6)
|
New discoveries and extensions in 2015 include
84.9
Bcfe and
41.0
Bcfe in the Haynesville shale and Bossier shale, respectively, related to our development of properties within the Shelby area of East Texas. Additionally, extensions and discoveries in 2015 included
24.7
Bcfe in the in the Haynesville shale related to the development of the Holly area in North Louisiana and
47.5
Bcfe in the Eagle Ford shale.
|
|
|
(7)
|
Total revisions due to Other factors include upward revisions of approximately
152.2
Bcfe in the North Louisiana Holly area and are primarily due to modifications in the well design to incorporate more proppant and longer laterals. The upward revisions also included
36.7
Bcfe from our East Texas region primarily due to strong results in both the Haynesville and Bossier shales based on our enhanced completion methods. The upward revisions also reflect a reduction in capital costs and operating expenses.
|
|
|
(8)
|
New discoveries and extensions in 2016 include
14.9
Bcfe in the Haynesville and Bossier shales related to our development of properties within the Shelby area of East Texas.
|
|
|
(9)
|
Total revisions due to Other factors include downward revisions of approximately
427.6
Bcfe as a result of the reclassification of our Proved Undeveloped Reserves to unproved during the first quarter of 2016 due to the uncertainty regarding the financing required to develop these reserves that existed on March 31, 2016. These reserves remained reclassified in unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, as the uncertainty regarding our ability of capital required to develop these reserves still existed at December 31, 2016. This was offset by approximately
99.0
Bcfe of upward revisions in the Marcellus shale primarily due to the narrowing of regional price differentials, reductions in our operating expenses, and improved well performance due to shallower declines than previously forecasted. The upward revision also reflects a reduction in operating expenses in other areas, primarily North Louisiana and South Texas, which increased our reserves by
51.4
Bcfe and
23.9
Bcfe, respectively. Lower operating costs were primarily the result of various cost reduction efforts, including significant reductions in labor costs, chemical treatment costs and saltwater disposal costs. Reductions in our operating costs extend the economic life of certain properties and resulted in upward revisions to our reserve quantities. In addition, the upward revisions in North Louisiana reflect improved performance of certain Haynesville shale wells that the Company turned-to-sales during 2016. These wells featured enhanced completion methods including more proppant per lateral foot.
|
|
|
(10)
|
The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.
|
Standardized measure of discounted future net cash flows
We have summarized the Standardized Measure related to our proved oil and natural gas reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a
10%
discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Furthermore, our ability to demonstrate that we have the financing available to fund a development program with Reasonable Certainty could have a significant impact on our Proved Undeveloped Reserves. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends.
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Year ended December 31, 2016:
|
|
|
Future cash inflows
|
|
$
|
1,216,855
|
|
Future production costs
|
|
705,873
|
|
Future development costs (1)
|
|
39,956
|
|
Future income taxes
|
|
—
|
|
Future net cash flows
|
|
471,026
|
|
Discount of future net cash flows at 10% per annum
|
|
160,095
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
310,931
|
|
Year ended December 31, 2015:
|
|
|
|
Future cash inflows
|
|
$
|
2,684,362
|
|
Future production costs
|
|
1,280,795
|
|
Future development costs
|
|
641,768
|
|
Future income taxes
|
|
—
|
|
Future net cash flows
|
|
761,799
|
|
Discount of future net cash flows at 10% per annum
|
|
359,666
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
402,133
|
|
Year ended December 31, 2014:
|
|
|
|
Future cash inflows
|
|
$
|
6,097,207
|
|
Future production costs
|
|
2,094,796
|
|
Future development costs
|
|
1,124,873
|
|
Future income taxes
|
|
—
|
|
Future net cash flows
|
|
2,877,538
|
|
Discount of future net cash flows at 10% per annum
|
|
1,334,951
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,542,587
|
|
|
|
(1)
|
All of our Proved Undeveloped Reserves were reclassified to unproved during 2016 due to the uncertainty regarding the financing required to develop these reserves. As such, future development costs at December 31, 2016 consist primarily of estimated future plugging and abandonment costs.
|
During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at
December 31, 2016
,
2015
and
2014
used in the above table, were
$42.75
,
$50.28
and
$94.99
per Bbl of oil, respectively, and
$2.48
,
$2.59
and
$4.35
per Mmbtu of natural gas, respectively. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differentials. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma.
The following are the principal sources of change in the Standardized Measure:
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Year ended December 31, 2016:
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(92,200
|
)
|
Net changes in prices and production costs
|
|
(260,335
|
)
|
Extensions and discoveries, net of future development and production costs
|
|
16,258
|
|
Development costs during the period
|
|
46,499
|
|
Changes in estimated future development costs
|
|
384,644
|
|
Revisions of previous quantity estimates
|
|
(180,367
|
)
|
Sales of reserves in place
|
|
(11,814
|
)
|
Purchase of reserves in place
|
|
347
|
|
Accretion of discount
|
|
40,213
|
|
Changes in timing and other
|
|
(34,447
|
)
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
(91,202
|
)
|
Year ended December 31, 2015:
|
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(153,404
|
)
|
Net changes in prices and production costs
|
|
(1,438,023
|
)
|
Extensions and discoveries, net of future development and production costs
|
|
99,818
|
|
Development costs during the period
|
|
109,895
|
|
Changes in estimated future development costs
|
|
407,780
|
|
Revisions of previous quantity estimates
|
|
(232,325
|
)
|
Sales of reserves in place
|
|
(1,632
|
)
|
Purchase of reserves in place
|
|
6,892
|
|
Accretion of discount
|
|
126,533
|
|
Changes in timing and other
|
|
(65,988
|
)
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
(1,140,454
|
)
|
Year ended December 31, 2014:
|
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(465,084
|
)
|
Net changes in prices and production costs
|
|
280,659
|
|
Extensions and discoveries, net of future development and production costs
|
|
196,796
|
|
Development costs during the period
|
|
189,155
|
|
Changes in estimated future development costs
|
|
(254,737
|
)
|
Revisions of previous quantity estimates
|
|
412,296
|
|
Sales of reserves in place
|
|
(148,226
|
)
|
Purchase of reserves in place
|
|
13,507
|
|
Accretion of discount
|
|
125,227
|
|
Changes in timing and other
|
|
(59,279
|
)
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
290,314
|
|
Costs not subject to amortization
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. A significant portion of our acreage is held-by-production, which allows us to develop these properties within an optimum time frame.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Total
|
|
2016
|
|
2015
|
|
2014
|
|
2013 and
prior
|
Property acquisition costs
|
|
$
|
61,757
|
|
|
$
|
899
|
|
|
$
|
11,121
|
|
|
$
|
7,862
|
|
|
$
|
41,875
|
|
Exploration and development
|
|
3,410
|
|
|
3,410
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Capitalized interest
|
|
31,913
|
|
|
5,213
|
|
|
8,464
|
|
|
8,604
|
|
|
9,632
|
|
Total
|
|
$
|
97,080
|
|
|
$
|
9,522
|
|
|
$
|
19,585
|
|
|
$
|
16,466
|
|
|
$
|
51,507
|
|
1.5 Lien Notes
On
March 15, 2017
, we issued an aggregate of
$300.0 million
of 1.5 Lien Notes to affiliates of Fairfax, Bluescape and Oaktree, and an unaffiliated investor. The 1.5 Lien Notes bear interest at a cash interest rate of
8%
per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certain circumstances, by issuing additional 1.5 Lien Notes, at an interest rate of
11%
per annum. Interest is payable bi-annually beginning on September 20, 2017. Investors were issued, at their election, either: (a) warrants to purchase our common shares at an exercise price of
$0.01
("Commitment Fee Warrants"), or (b) cash. This resulted in the payments of
$4.5 million
in cash and the issuance of
6,471,433
Commitment Fee Warrants. In addition, investors were issued
322,580,655
warrants to purchase our common shares at an exercise price of
$0.93
per share ("Financing Warrants"). The proceeds from the issuance of the 1.5 Lien Notes were primarily used to repay the outstanding indebtedness under the EXCO Resources Credit Agreement.
The 1.5 Lien Notes are jointly and severally guaranteed by all of the our subsidiaries that guarantee our indebtedness under the EXCO Resources Credit Agreement and the Second Lien Term Loans, and are secured by first priority liens on substantially all of our assets and such guarantors. The 1.5 Lien Notes rank
pari passu
in right of payment with one another and all of our other existing and future senior indebtedness, including debt under the EXCO Resources Credit Agreement, the 1.75 Lien Term Loans, the Second Lien Term Loans and the 2018 Notes and 2022 Notes. However, as a result of the debt under the EXCO Resources Credit Agreement having a priority claim to the collateral securing the 1.5 Lien Notes, the 1.5 Lien Notes are (i) effectively junior to debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii)
pari passu
with one another, (iii) effectively senior to the 1.75 Lien Term Loans, the Second Lien Term Loans and any third lien obligations and (iv) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and 2022 Notes, in each case to the extent of the collateral.
1.75 Lien Term Loans and the Second Lien Term Loan Exchange
On
March 15, 2017
, in connection with the issuance of the 1.5 Lien Notes, we closed an exchange of an aggregate of
$682.8 million
of 1.75 Lien Term Loans for an aggregate of
$682.8 million
of Second Lien Term Loans ("Second Lien Term Loan Exchange"). Exchanging Second Lien Term Loan lenders were issued, at their election, either: (a) warrants to purchase our common shares at an exercise price of
$0.01
("Amendment Fee Warrants," collectively referred to as the "2017 Warrants" with the Commitment Fee Warrants and Financing Warrants) or (b) cash. This resulted in the payments of
$8.6 million
in cash and the issuance of
19,883,077
Amendment Fee Warrants.
The 1.75 Lien Term Loans bear interest at a cash rate of
12.5%
per annum, or, if we elect to pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien Term Loans, at an interest rate of
15.0%
per annum. The 1.75 Lien Term Loans are jointly and severally guaranteed by all of our subsidiaries that guarantee the indebtedness under the EXCO Resources Credit Agreement and the Second Lien Term Loans, and are secured by first priority liens on substantially all of our assets and such guarantors. The 1.75 Lien Term Loans rank
pari passu
in right of payment with one another and all of our other existing and future senior indebtedness, including debt under the EXCO Resources Credit Agreement, the 1.5 Lien Notes, the Second Lien Term Loans and the 2018 Notes and 2022 Notes. However, as a result of the debt under the EXCO Resources Credit Agreement and the 1.5 Lien Notes having a priority claim to the collateral securing the 1.75 Lien Term Loans, the 1.75 Lien Term Loans rank (i) effectively junior to debt under the EXCO Resources Credit Agreement, the 1.5 Lien Notes and any other priority lien obligations, (ii)
pari passu
with one another, (iii) effectively senior to the Second Lien Term Loans and any third lien obligations and (iv) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and 2022 Notes, in each case to the extent of the collateral.
By participating in the Second Lien Term Loan Exchange, each exchanging lender was deemed to consent to an amendment to the Second Lien Term Loans that eliminated substantially all of the restrictive covenants and events of default in the agreements governing the Second Lien Term Loans.
In connection with the issuance of the 1.5 Lien Notes and the Second Lien Term Loan Exchange, we entered into a new intercreditor agreement governing the relationship between EXCO’s lenders and the holders of any other lien obligations that EXCO may issue in the future with respect to the collateral securing such obligations and certain other matters.
PIK Payments Under the 1.5 Lien Notes and the 1.75 Lien Term Loans
The indenture governing the 1.5 Lien Notes and the agreement governing the 1.75 Lien Term Loans allow us to make PIK Payments subject to certain limitations. Under the indenture governing the 1.5 Lien Notes and the agreement governing the 1.75 Lien Term Loans, the price of our common shares for determining PIK Payments is based on the trailing 20-day volume weighted average price calculated on the third trading day prior to the interest payment date. Our ability to issue common shares for the PIK Payments is restricted and subject to certain conditions, including the following: (i) we shall have obtained the requisite shareholder approvals related to proposals to permit the issuances of common shares represented by the 2017 Warrants and PIK Payments for purposes of the rules of the New York Stock Exchange ("NYSE"), and amend our charter to increase its authorized common shares or execute a reverse stock split, without a proportionate reduction of authorized shares, at the discretion of the Board of Directors (collectively referred to as "Requisite Shareholder Approval"); however, we may waive the requirement within the 1.5 Lien Notes and 1.75 Lien Term Loans to obtain shareholder approval to amend our charter at our sole discretion, and (ii) the issuance of common shares does not result in a beneficial owner, directly or indirectly, owning more than
50%
of the outstanding common stock, and (iii) the common shares issued in connection with the PIK Payments shall be registered under an effective registration statement under the Securities Act. If the Requisite Shareholder Approvals are not obtained by
September 30, 2017
, subject to certain extensions, the cash interest on the 1.5 Lien Notes shall accrue at a rate of
15.0%
per annum and the interest rate for PIK Payments shall accrue at a rate of
20.0%
per annum. The amount of PIK Payments made in additional 1.5 Lien Notes or 1.75 Lien Term Loans is subject to incurrence covenants within our debt agreements that limit our aggregate secured indebtedness to
$1.2 billion
.
Prior to December 31, 2018, we may make PIK Payments on the 1.5 Lien Notes and the 1.75 Lien Term Loans in our sole discretion. After December 31, 2018, we are only permitted to make PIK Payments in the following percentages of interest due based on our liquidity, which, for the purposes of 1.5 Lien Notes and 1.75 Lien Term Loans, is defined as (i) the sum of (a) our unrestricted cash and cash equivalents and (b) any amounts available to be borrowed under the EXCO Resources Credit Agreement (to the extent then available) less (ii) the face amount of any letters of credit outstanding under the EXCO Resources Credit Agreement:
|
|
|
|
Liquidity Level
|
|
PIK Payment Percentage
|
Less than $150 million
|
|
100%
|
$150 million or greater but less than $175 million
|
|
75%
|
$175 million or greater but less than $200 million
|
|
50%
|
$200 million or greater but less than $225 million
|
|
25%
|
$225 million or greater
|
|
—%
|
Covenants, events of default and other material provisions
The covenants and events of default under the indenture governing the 1.5 Lien Notes and the agreement governing the 1.75 Lien Term Loans are substantially similar to those under the Second Lien Term Loans prior to giving effect to the amendment to the Second Lien Term Loans resulting from the Second Lien Term Loan Exchange. Subject to certain exceptions, the covenants under the indenture governing the 1.5 Lien Notes and the agreement governing the 1.75 Lien Term Loans limit our ability and the ability of our subsidiary guarantors to, among other things:
|
|
•
|
pay dividends or make other distributions or redeem or repurchase our capital stock;
|
|
|
•
|
prepay, redeem or repurchase certain debt;
|
|
|
•
|
enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advances to us or transfer assets to us;
|
|
|
•
|
engage in asset sales or substantially alter the business that we conduct;
|
|
|
•
|
enter into transactions with affiliates;
|
|
|
•
|
consolidate, merge or dispose of assets;
|
|
|
•
|
incur indebtedness and liens; and
|
|
|
•
|
enter into sale/leaseback transactions.
|
In addition, the indenture governing the 1.5 Lien Notes includes restrictions on our ability to incur additional indebtedness, including debt under the EXCO Resources Credit Agreement in excess of
$150.0 million
, among other things and subject to certain restrictions. We may incur debt under the EXCO Resources Credit Agreement up to
$200.0 million
if we obtain consent from holders of a majority in principal amount of the 1.5 Lien Notes.
An event of default under the indenture governing the 1.5 Lien Notes will cause both the cash interest rate and PIK payment interest rate to increase by an additional
2%
per annum. The indenture governing the 1.5 Lien Notes also provides that, upon a change of control, the holders of the 1.5 Lien Notes will have the right to require us to repurchase their 1.5 Lien Notes at
101%
of the aggregate principal amount outstanding, plus accrued and unpaid interest.
Warrants
Subject to certain exceptions, the 2017 Warrants may not be exercised unless and until the Requisite Shareholder Approval is obtained. In addition, subject to certain exceptions and limitations, the 2017 Warrants may not be exercised if, as a result of such exercise, the holder of such 2017 Warrant 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 the date that the Requisite Shareholder Approvals are obtained and may be exercised by cash or cashless exercise, provided that we may require cashless exercise if the cash exercise of any 2017 Warrant would negatively impact our ability to utilize net operating losses for U.S. federal income tax purposes. The 2017 Warrants also contain anti-dilution protection in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the 2017 Warrants.
Amendment to EXCO Resources Credit Agreement
Concurrently with the issuance of the 1.5 Lien Notes and as a condition precedent thereto, we amended the EXCO Resources Credit Agreement to, among other things, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, reduce the borrowing base thereunder to
$150.0 million
and modify certain financial covenants. The next borrowing base redetermination for the EXCO Resources Credit Agreement is scheduled to occur on or around November 1, 2017. In the event we divest our South Texas assets, we would not be able to request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed
$100.0 million
, including letters of credit, until the next redetermination. The amended financial covenants include the following:
|
|
•
|
our cash (as defined in the agreement) plus unused commitments under the EXCO Resources Credit Agreement cannot be less than (i)
$50.0 million
as of the end of a fiscal month and (ii)
$70.0 million
as of the end of a fiscal quarter ("Minimum Liquidity Test");
|
|
|
•
|
our Interest Coverage Ratio must exceed a minimum of
1.75
to 1.0 for the fiscal quarter ending September 30, 2017 and
2.0
to 1.0 for fiscal quarters thereafter. The consolidated EBITDAX and consolidated interest expense utilized in this ratio are based on the most recent fiscal quarter ended multiplied by
4.0
as of September 30, 2017, the most recent two fiscal quarters ended multiplied by
2.0
as of December 31, 2017, the most recent three fiscal quarters ended multiplied by
4/3
as of March 31, 2018, and the trailing twelve month period for fiscal quarters ending thereafter. The definition of consolidated interest expense was modified to include cash interest payments that are accounted for as reductions in the carrying amount of indebtedness in accordance with FASB ASC 470-60. Consolidated interest expense is limited to payments in cash, and excludes PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans; and
|
|
|
•
|
our ratio of aggregate revolving credit exposure to consolidated EBITDAX ("Aggregate Revolving Credit Exposure Ratio") cannot exceed
1.2
to 1.0 as of the end of any fiscal quarter. Aggregate revolving credit exposure utilized in the Aggregate Revolving Credit Exposure Ratio includes borrowings and letters of credit under the EXCO Resources Credit Agreement.
|
In addition, the EXCO Resources Credit Agreement requires us to furnish our audited financial statements within 90 days after the fiscal year end without a going concern or like qualification. The requirement that such financial statements be delivered without a going concern qualification has been waived for financial statements relating to the 2016 fiscal year.
The amendment also permits optional payments for existing senior unsecured notes provided, after giving pro forma effect to any such prepayment, repayment, exchange, redemption, defeasance or repurchase, (i) the sum of the unused commitments under the EXCO Resources Credit Agreement plus unrestricted cash and cash equivalents is equal to or greater than
$100.0 million
and (ii) the repurchase in cash of existing senior unsecured notes does not exceed
$75.0 million
in the aggregate.
Additional Information Concerning the 1.5 Lien Notes and the Second Lien Term Loan Exchange
The foregoing description of the indenture governing the 1.5 Lien Notes, the agreement governing the 1.75 Lien Term Loans, the amendment to the EXCO Resources Credit Agreement, and the intercreditor agreement does not purport to be complete, and is qualified by reference to indenture governing the 1.5 Lien Notes, the agreement governing 1.75 Lien Term Loans, the amendment to the EXCO Resources Credit Agreement, and the intercreditor agreement, which were filed as exhibits to our Current Report on Form 8-K, dated
March 15, 2017
and filed with the SEC on
March 15, 2017
.