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.
•
Appalachia
The Appalachia region is primarily comprised of our Marcellus shale assets. We had a joint venture with Shell covering our Marcellus shale and other assets in the Appalachia region ("Appalachia JV"). EXCO and Shell each owned an undivided
50%
interest in the Appalachia JV and a
49.75%
working interest in the Appalachia JV's properties. The remaining
0.5%
working interest is held by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We owned a
50%
interest in OPCO. On
February 27, 2018
, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region ("Appalachia JV Settlement"). As a result of the Appalachia JV Settlement, we acquired Shell's interests in the Appalachia JV and OPCO. See further discussion of this settlement as part of "Note 17. Subsequent events".
The accompanying Consolidated Balance Sheets as of
December 31, 2017
and
2016
, Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended
December 31, 2017
,
2016
and
2015
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.
Reverse share split
On June 2, 2017, we filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorized common shares from
780,000,000
to
260,000,000
and effect a 1-for-
15
reverse share split. The reverse share split became effective after the market closed on June 12, 2017. The par value of the common shares remained unchanged at
$0.001
per share, which required retrospective reclassification from common shares to additional paid-in capital within the shareholders' equity section of our consolidated balance sheets. Shareholders' equity and all share data, including treasury shares, and per share data presented herein have been retrospectively adjusted to reflect the impact of the decrease in authorized shares and the reverse share split, as appropriate.
Chapter 11 Cases and Going Concern Assessment
On January 15, 2018, the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP, Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief
under Chapter 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (“Court”). The Chapter 11 cases are being jointly administered under the caption
In Re EXCO Resources, Inc., Case No. 18-30155 (MI)
("Chapter 11 Cases"). The Court granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.
For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings described in "Item 1A. Risk Factors”. As a result of these risks and uncertainties, our assets, liabilities, shareholders' equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases. See further discussion of the Chapter 11 proceedings in "Note 17. Subsequent events".
We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. The significant risks and uncertainties related to our Liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. These Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.
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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,
2017
and
2016
and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31,
2017
,
2016
and
2015
. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated.
Management estimates
In preparing the Consolidated Financial Statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates.
Cash equivalents
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Restricted cash
The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with Shell that is used to fund our share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana.
Concentration of credit risk and accounts receivable
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have
sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both
December 31, 2017
and
2016
. 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, 2017
, 2016 and 2015, sales to BG Energy Merchants LLC, and subsequently a subsidiary of Shell accounted for approximately
32%
,
24%
and
20%
, 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. In January 2018, we discontinued the sale of natural gas to Shell in the East Texas and North Louisiana regions as a result of litigation regarding certain natural gas sales contracts. See further discussion in "Item 3. Legal proceedings" and in "Note 8. Commitments and contingencies". We have not experienced any interruptions or negative impact to our natural gas sales prices as a result the discontinuance of sales to Shell in these regions. For the years ended
December 31, 2017
,
2016
and
2015
, Chesapeake Energy Marketing Inc. accounted for approximately
17%
,
32%
, and
38%
respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake").
Derivative financial instruments
Our derivative financial instruments are comprised of commodity derivative contracts and the 2017 Warrants (as defined in "Note 4. Derivative financial instruments"). We use commodity 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 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
$118.7 million
and
$97.1 million
as of
December 31, 2017
and
2016
, 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
2017
and 2016 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 capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by
the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the relationship between capitalized costs and Proved Reserves.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at
10%
, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.
The ceiling test for each period 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, 2017
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$
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51.34
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$
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2.98
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December 31, 2016
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42.75
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2.48
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December 31, 2015
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50.28
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2.59
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For the year ended
December 31, 2017
, we did
no
t recognize impairments to our proved oil and natural gas properties. For the year ended December 31, 2016 and 2015, we recognized impairments to our proved oil and natural gas properties of
$160.8 million
and
$1.2 billion
, respectively. The impairments were primarily due to the decline in oil and natural gas prices.
As of December 31, 2017, we did not recognize any Proved Undeveloped Reserves due to our inability to meet the Reasonable Certainty criteria as prescribed under the SEC requirements as a result of the uncertainty regarding our availability of capital required to develop these reserves. We have a significant amount of reserves that would meet the criteria to be classified as Proved Undeveloped Reserves if we were able to demonstrate 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, net and other non-current assets
Other property and equipment, net and other non-current assets is primarily comprised of surface acreage and buildings and equipment associated with field offices located in our South Texas region. The buildings and equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from
3
to
15
years.
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 consider our enterprise value, calculated as the combined market capitalization of our equity plus the fair value of our debt, in determining the fair value of our reporting unit. As part of the determination of the fair value of our reporting unit, we corroborate our enterprise value to the results of the valuation model in which we apply a two-part, equally weighted approach in determining the fair value of our business. 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 a result of testing, the fair value of our business significantly exceeded the carrying value of net assets at
December 31, 2017
and we did
no
t record an impairment charge for the periods ending
December 31, 2017
,
2016
or
2015
.
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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2017
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2016
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|
2015
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Asset retirement obligations at beginning of period
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$
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11,289
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|
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$
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41,648
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|
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$
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36,755
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Activity during the period:
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|
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Liabilities incurred during the period
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12
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|
|
—
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881
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|
Revisions in estimated assumptions
|
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—
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|
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175
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|
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3,215
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|
Liabilities settled during the period
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(175
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)
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|
(140
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)
|
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(293
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)
|
Adjustment to liability due to acquisitions
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17
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|
|
1
|
|
|
180
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|
Adjustment to liability due to divestitures (1)
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—
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|
|
(32,605
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)
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(1,367
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)
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Accretion of discount
|
|
874
|
|
|
2,210
|
|
|
2,277
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Asset retirement obligations at end of period
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12,017
|
|
|
11,289
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|
|
41,648
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Less current portion
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600
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|
344
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|
845
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Long-term portion
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$
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11,417
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$
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10,945
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$
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40,803
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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.
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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, 2017
,
2016
and
2015
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
$111.4 million
,
$106.5 million
and
$99.3 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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, 2017
,
2016
and
2015
, we capitalized
$3.9 million
,
$4.0 million
and
$10.6 million
, respectively. The capitalized amounts include
$1.0 million
,
$0.8 million
and
$3.4 million
of share-based compensation for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners of
$14.6 million
,
$13.7 million
and
$13.1 million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively, as a reduction of general and administrative expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of
$6.0 million
,
$5.8 million
and
$5.7 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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. For the years ended December 31,
2017
,
2016
and
2015
, general and administrative expenses were reduced by
$6.4 million
,
$7.1 million
and
$15.9 million
, respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by Shell for their personnel and services.
Environmental costs
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes
Income taxes are accounted for in accordance with FASB ASC 740,
Income Taxes
("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings per share
We account for earnings per share in accordance with FASB ASC 260-10,
Earnings Per Share
("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"): basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period and includes warrants representing the right to purchase our common shares at an exercise price of
$0.01
. Basic EPS excludes stock options, restricted share units, restricted share awards, warrants issued Energy Strategic Advisory Services LLC ("ESAS", the warrants are referred to as "ESAS Warrants") and Financing Warrants (as defined in "Note 4. Derivative financial instruments"). Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents,
which include stock options, restricted share units, restricted share awards, ESAS Warrants and Financing Warrants, whether exercisable or not.
Equity-based compensation
Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC 718,
Compensation-Stock Compensation
("ASC 718") and equity-based compensation for ESAS Warrants which we accounted for in accordance with FASB ASC 505-50,
Equity-Based Payments to Non-Employees
("ASC 505-50"). See "Note 13. Related party transactions" for further discussion.
ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.
Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards. We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there were no grants of share-based compensation during 2017. See further discussion in "Note 11. Equity-based and other incentive-based compensation".
The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment was recorded in our Consolidated Statements of Operations included as equity-based compensation expense. The ESAS Warrants were forfeited and canceled on November 9, 2017 concurrently with the suspension of the services and investment agreement with ESAS. See "Note 11. Equity-based and other incentive-based compensation" for additional information of the ESAS Warrants.
Recent accounting pronouncements
In February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02,
Leases
(Topic 842) ("ASU 2016-02"). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. 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 may have an impact on our consolidated financial condition and results of operations upon adoption.
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, and early adoption is permitted. We adopted ASU 2016-15 in the fourth quarter of 2017, and elected to apply the cumulative earnings approach to classify distributions received from equity method investees.
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 assessed ASU 2016-16 and concluded it did not have an impact 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 are currently assessing the potential impact of ASU 2016-18 on our consolidated financial condition and results of operations and will apply ASU 2016-18 beginning with the first quarter of 2018.
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 this threshold is 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 and will apply ASU 2017-07 to future asset acquisitions occurring in annual and interim periods beginning after December 15, 2017.
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 early adopted ASU 2017-04 during 2017, and will apply the guidance in ASU 2017-04, if applicable, to future goodwill impairment tests.
In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718):
Scope of Modification Accounting
("ASU 2017-09"). ASU 2017-09 provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. ASU 2017-09 is effective for annual and interim periods beginning after December 15, 2017, and early adoption is permitted. We adopted ASU 2017-09 in the current period; however, the adoption of ASU 2017-09 did not have an impact on our consolidated financial condition and results of operations. We will apply the guidance in ASU 2017-09 in future periods, if applicable.
In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815):
I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception
("ASU 2017-11"). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40,
Derivatives and Hedging -
Contracts in Entity’s Own Equity
, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. An entity still is required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it may have a significant impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. During the year ended December 31, 2017, we recorded a gain of
$159.2 million
on the revaluation of the 2017 Warrants on the Consolidated Statements of Operations and a liability of
$2.0 million
on the Consolidated Balance Sheet as of December 31, 2017.
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. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method.
We are substantially complete with our assessment of the impact of ASU 2014-09 and the related updates and clarifications. ASU 2014-09 and the related updates will be implemented for the interim and annual periods beginning after December 15, 2017 and the new standard will be applied using the modified retrospective method of adoption. We do not believe this standard will have a material impact, if any, on our consolidated financial condition and results of operations. However, the adoption of the standard will require that we provide expanded disclosures related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We plan to complete the implementation of processes to ensure new contracts are reviewed for the appropriate accounting treatment and generate the disclosures required under the new standard prior to the filing of our Form 10-Q for the three months ended March 31, 2018.
|
|
3.
|
Acquisitions, divestitures and other significant events
|
2017 Acquisitions and termination of South Texas divestiture
Termination of South Texas divestiture
On April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil and natural gas properties and surface acreage in South Texas for a total purchase price of
$300.0 million
that was subject to closing conditions and adjustments based on an effective date of January 1, 2017.
Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original Scheduled Closing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreement included conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as of the Original Scheduled Closing Date. On May 31, 2017, Chesapeake Energy Marketing, L.L.C. (“CEML”) purportedly terminated a long-term natural gas sales contract with an expiration of June 30, 2032, between CEML and Raider Marketing, LP (“Raider”), a wholly owned subsidiary of EXCO.
On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against CEML and subsequently added the parent entity, Chesapeake Energy Corporation ("CEC"). In the lawsuit, we assert breach of contract, tortious interference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, CEML filed to remove the lawsuit to the United States
District Court Northern District of Texas. On June 9, 2017, the District Court denied our motion for temporary restraining order. CEC filed a motion to dismiss on the basis of personal jurisdiction, and the motion remains pending.
Due to the purported contract termination, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date. Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017. The amendment, among other things, provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of the natural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017, EXCO and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no further effect.
North Louisiana acquisitions
During the year ended December 31, 2017, we closed acquisitions of certain oil and natural gas properties and undeveloped acreage in the North Louisiana region for
$24.2 million
. The total purchase price was primarily allocated to
$5.2 million
of unproved oil and natural gas properties and
$19.0 million
of proved oil and natural gas properties.
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 (as defined in "Note 5. Debt").
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.
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.
|
|
4.
|
Derivative financial instruments
|
Our derivative financial instruments are comprised of commodity derivative contracts and common share warrants.
The table below presents the effect of derivative financial instruments on our Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
Current assets
|
|
Derivative financial instruments - commodity derivatives
|
|
$
|
1,150
|
|
|
$
|
—
|
|
Long-term assets
|
|
Derivative financial instruments - commodity derivatives
|
|
—
|
|
|
482
|
|
Current liabilities
|
|
Derivative financial instruments - commodity derivatives
|
|
—
|
|
|
(27,711
|
)
|
Long-term liabilities
|
|
Derivative financial instruments - commodity derivatives
|
|
—
|
|
|
(464
|
)
|
|
|
Net commodity derivative financial instruments
|
|
$
|
1,150
|
|
|
$
|
(27,693
|
)
|
|
|
|
|
|
|
|
Long-term liabilities
|
|
Derivative financial instruments - common share warrants
|
|
$
|
(1,950
|
)
|
|
$
|
—
|
|
The table below presents the effect of derivative financial instruments on our Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Gain (loss) on derivative financial instruments - commodity derivatives
|
|
$
|
24,732
|
|
|
$
|
(34,137
|
)
|
|
$
|
75,869
|
|
Gain on derivative financial instruments - common share warrants
|
|
159,190
|
|
|
—
|
|
|
—
|
|
Commodity derivative financial instruments
Our primary objective in entering into commodity 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 commodity derivative financial instruments consists of non-cash income or expense due to changes in the fair value. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our commodity derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.
Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Consolidated Balance Sheets fair value amounts.
Our oil and natural gas derivative instruments have historically been 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.
We have historically entered into commodity derivative financial instruments with the financial institutions that are lenders under the EXCO Resources Credit Agreement. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity 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 have restricted our ability to enter into certain types of commodity derivative financial instruments and limited the maturity of the contracts with counterparties. The DIP Credit Agreement (as defined in "Note 5. Debt") permits us to enter into commodity derivative contracts up to 90% of the reasonably anticipated projected production from our proved developed producing reserves for any month during the forthcoming five year period. We are only permitted to enter into additional commodity derivative contracts with lenders under the DIP Credit Agreement.
The following table presents the volumes and fair value of our commodity derivative financial instruments as of
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars in thousands, except prices)
|
|
Volume (Bbtu)
|
|
Weighted average strike price per Mmbtu
|
|
Fair value at December 31, 2017
|
Natural gas:
|
|
|
|
|
|
|
Swaps:
|
|
|
|
|
|
|
2018
|
|
3,650
|
|
|
$
|
3.15
|
|
|
$
|
1,150
|
|
In January 2018, the counterparty to our remaining swap contracts early terminated the outstanding contracts effective January 31, 2018. We received proceeds of
$0.5 million
for the settlement these contracts in February 2018. As a result, our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels.
At
December 31, 2016
, we had outstanding swap and collar contracts covering
41,950
and
10,950
Bbtu of natural gas, respectively, and outstanding swap contracts covering
183
Mbbls of oil.
At
December 31, 2017
, the average forward NYMEX HH natural gas price per Mmbtu for the calendar year
2018
was
$2.84
.
Our commodity derivative financial instruments covered approximately
58%
and
57%
of production volumes
for the years ended
December 31, 2017
and
2016
.
Common share warrants
In connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of 1.5 Lien Notes representing the right to purchase an aggregate of up to
21,505,383
common shares (assuming a cash exercise) at an exercise price of
$13.95
per share ("Financing Warrants"), and warrants representing the right to purchase an aggregate of up to
431,433
common shares (assuming a cash exercise) at an exercise price of
$0.01
per share (“Commitment Fee Warrants”). In addition, certain exchanging holders of the Second Lien Term Loans received warrants representing the right to purchase an
aggregate of up to
1,325,546
common shares (assuming a cash exercise) at an exercise price of
$0.01
per share ("Amendment Fee Warrants", and with the Commitment Fee Warrants and Financing Warrants, collectively referred to as the "2017 Warrants"). See "Note 5. Debt" for further discussion of the Second Lien Term Loans.
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 Warrants or its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exercise term of
5
years from May 31, 2017 and, subject to certain exceptions, may be exercised by cash or cashless exercise. The Financing Warrants are subject to an anti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the Financing Warrants, subject to certain adjustments and exceptions. The Commitment Fee Warrants and the Amendment Fee Warrants are subject to an anti-dilution adjustment in the event we issue common shares at a price per share less than
$10.50
per share, subject to certain exceptions and adjustments. The 2017 Warrants are accounted for as derivatives in accordance with ASC 815, and required to be classified as liabilities due to the types of anti-dilution adjustments.
We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. The 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise, cancellation or expiration. As a result of the change in the fair value of the 2017 Warrants, we recorded a gain of
$159.2 million
on the revaluation of the warrants during year ended December 31, 2017 in "Gain on derivative financial instruments - common share warrants" on the Consolidated Statements of Operations. The gain was primarily due to a decrease in EXCO's share price. In January 2018, the 2017 Warrants held by affiliates of Fairfax were canceled; see further discussion in "Note 13. Related party transactions".
The carrying value of our total debt is summarized as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2017
|
|
December 31, 2016
|
EXCO Resources Credit Agreement
|
|
$
|
126,401
|
|
|
$
|
228,592
|
|
1.5 Lien Notes, net of unamortized discount
|
|
176,560
|
|
|
—
|
|
1.75 Lien Term Loans, net of unamortized discount
|
|
845,763
|
|
|
—
|
|
Exchange Term Loan
|
|
23,543
|
|
|
590,477
|
|
Fairfax Term Loan
|
|
—
|
|
|
300,000
|
|
2018 Notes, net of unamortized discount
|
|
131,345
|
|
|
131,056
|
|
2022 Notes
|
|
70,169
|
|
|
70,169
|
|
Deferred financing costs, net
|
|
(11,281
|
)
|
|
(11,756
|
)
|
Total debt, net
|
|
1,362,500
|
|
|
1,308,538
|
|
Less amounts due within one year
|
|
1,362,500
|
|
|
50,000
|
|
Total debt due after one year
|
|
$
|
—
|
|
|
$
|
1,258,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
(in thousands)
|
|
Carrying value
|
|
Deferred reduction in carrying value
|
|
Unamortized discount/deferred financing costs
|
|
Principal balance
|
EXCO Resources Credit Agreement
|
|
$
|
126,401
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
126,401
|
|
1.5 Lien Notes
|
|
176,560
|
|
|
—
|
|
|
140,398
|
|
|
316,958
|
|
1.75 Lien Term Loans
|
|
845,763
|
|
|
(154,171
|
)
|
|
17,334
|
|
|
708,926
|
|
Exchange Term Loan
|
|
23,543
|
|
|
(6,297
|
)
|
|
—
|
|
|
17,246
|
|
2018 Notes
|
|
131,345
|
|
|
—
|
|
|
231
|
|
|
131,576
|
|
2022 Notes
|
|
70,169
|
|
|
—
|
|
|
—
|
|
|
70,169
|
|
Deferred financing costs, net
|
|
(11,281
|
)
|
|
—
|
|
|
11,281
|
|
|
—
|
|
Total debt
|
|
$
|
1,362,500
|
|
|
$
|
(160,468
|
)
|
|
$
|
169,244
|
|
|
$
|
1,371,276
|
|
Terms and conditions of each of these debt obligations are discussed below.
DIP Credit Agreement
On January 22, 2018, we closed a Debtor-in-Possession Credit Agreement (“DIP Credit Agreement”), which includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of
$125.0 million
(“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of
$125.0 million
(“Revolver B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). The proceeds from the DIP Credit Agreement were used to refinance all obligations outstanding under our credit agreement ("EXCO Resources Credit Agreement") and provide additional liquidity to fund our operations during the Chapter 11 Cases. See further discussion of the DIP Credit Agreement in "Note 17. Subsequent events".
EXCO Resources Credit Agreement
As of December 31, 2017, we borrowed substantially all of our remaining unused commitments and had
$126.4 million
of outstanding indebtedness and
$23.0 million
of outstanding letters of credit under the EXCO Resources Credit Agreement as of December 31, 2017. The borrowing base under the EXCO Resources Credit agreement was
$150.0 million
as of December 31, 2017. As a result, the availability remaining under the EXCO Resources Credit Agreement, including letters of credit, was
$0.6 million
as of December 31, 2017. Borrowings under the EXCO Resources Credit Agreement were collateralized by first lien mortgages providing a security interest of not less than
80%
of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. As discussed above, the proceeds from the DIP Facilities were used to refinance all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated.
The maturity date of the EXCO Resources Credit Agreement was
July 31, 2018
. The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranged from London Interbank Offered Rate ("LIBOR") plus 250 bps to 350 bps (or alternate base rate ("ABR") plus 150 bps to 250 bps), depending on our borrowing base usage. On
December 31, 2017
, our interest rate was approximately
4.9%
.
Concurrently with the issuance of the 1.5 Lien Notes and as a condition precedent thereto, on March 15, 2017, 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. Our financial covenants (as defined in the EXCO Resources Credit Agreement), required that:
|
|
•
|
our cash (as defined in the EXCO Resources Credit 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;
|
|
|
•
|
our Aggregate Revolving Credit Exposure Ratio (as defined in the EXCO Resources Credit Agreement) 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; and
|
|
|
•
|
our Interest Coverage Ratio cannot be less than
2.0
to 1.0. The consolidated EBITDAX and consolidated interest expense utilized in this ratio are based on the 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 includes cash interest payments that are accounted for as reductions in the carrying amount of indebtedness in accordance with FASB ASC 470-60,
Troubled Debt Restructuring by Debtors
. Consolidated interest expense is limited to payments in cash, and excludes PIK Payments (as defined below) on the 1.5 Lien Notes and 1.75 Lien Term Loans (as defined below).
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On December 19, 2017, we entered into a forbearance agreement with the lenders under the EXCO Resources Credit Agreement. Pursuant to this agreement, the lenders under the EXCO Resources Credit Agreement agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement. An event of default as a result of a breach of any covenant under the EXCO Resources Credit Agreement could also cause an event of default under the indenture governing the 1.5 Lien Notes, credit agreement governing the 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes. FASB ASC 470,
Debt
, requires debt to be presented as a current liability if a debtor modifies a covenant in anticipation of a potential default and it is probable the debtor will not be able meet the covenant in future periods. Therefore, we have classified the amounts outstanding under the EXCO Resources Credit Agreement, as well as any outstanding debt with cross-default provisions, as a current liability.
1.5 Lien Notes
On March 15, 2017, we issued an aggregate of
$300.0 million
of 1.5 Lien Notes due March 20, 2022 to affiliates of Fairfax Financial Holdings Limited ("Fairfax"), Bluescape Resources Company LLC ("Bluescape"), Oaktree Capital Management, LP ("Oaktree"), and an unaffiliated investor. The 1.5 Lien Notes bear interest at a cash interest rate of
8%
per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certain circumstances, by issuing additional 1.5 Lien Notes, at an interest rate of
11%
per annum. Interest is payable bi-annually on March 20 and September 20 of each year, commencing on September 20, 2017. On September 20, 2017 we paid the interest due on the 1.5 Lien Notes in-kind with approximately
$17.0 million
of aggregate principal amount of 1.5 Lien Notes, resulting in
$317.0 million
of total aggregate principal amount of 1.5 Lien Notes outstanding. On December 19, 2017, we entered into a forbearance agreement with certain lenders under the 1.5 Lien Notes. Pursuant to this agreement, the lenders under the 1.5 Lien Notes agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement.
As described in “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.5 Lien Notes, we also issued the Commitment Fee Warrants and the Financing Warrants. The combined fair value of the Commitment Fee Warrants and the Financing Warrants of
$148.6 million
as of March 15, 2017 and
$4.5 million
of cash paid to certain investors who elected to receive cash in lieu of Commitment Fee Warrants was recorded as a discount to the 1.5 Lien Notes. The discount and
$4.3 million
of transaction costs incurred related to the transaction are being amortized to interest expense over the life of the 1.5 Lien Notes. We used the majority of the proceeds from the issuance of the 1.5 Lien Notes to repay the entire amount outstanding under the EXCO Resources Credit Agreement in March 2017.
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, 1.75 Lien Term Loans 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 Second Lien Term Loan Exchange
During 2015, we closed a
12.5%
senior secured second lien term loan with certain affiliates of Fairfax in the aggregate principal amount of
$300.0 million
("Fairfax Term Loan") and a
12.5%
senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of
$400.0 million
(“Exchange Term Loan" and together with the Fairfax Term Loan, "Second Lien Term Loans"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60,
Troubled Debt Restructuring by Debtors
. 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 was adjusted to equal 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, reduce the carrying amount and no interest expense is recognized.
In connection with the offering of the 1.5 Lien Notes, on March 15, 2017, we completed the Second Lien Term Loan Exchange whereby approximately
$682.8 million
in aggregate principal amount of the outstanding Second Lien Term Loans, consisting of all of the outstanding indebtedness under the Fairfax Term Loan and approximately
$382.8 million
in aggregate principal amount of the Exchange Term Loan, were exchanged for approximately
$682.8 million
in aggregate principal amount of 1.75 Lien Term Loans. As a result of the Second Lien Term Loan Exchange, the Fairfax Term Loan was deemed satisfied and paid in full and was terminated. In addition, by participating in the Second Lien Term Loan Exchange, each exchanging lender was deemed to 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. Following the Second Lien Term Loan Exchange, the Company has approximately
$17.2 million
in aggregate principal amount of Second Lien Term Loans outstanding, consisting entirely of the remaining portion of the Exchange Term Loan.
The Second Lien Term Loan Exchange was accounted for as a modification of debt, and no gain or loss was recognized on the exchange. As described in “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.75 Lien Term Loans, we also issued the Amendment Fee Warrants. The combined fair value of the Amendment Fee Warrants issued to the lenders of the 1.75 Lien Term Loans on March 15, 2017 of
$12.6 million
and
$8.6 million
of cash paid to the lenders who elected to receive cash in lieu of warrants was recorded as a discount to the 1.75 Lien Term Loans, and is being amortized to interest expense over the life of the loans. The transaction costs related to the Second Lien Term Loan Exchange of
$6.4 million
were recorded in "Gain (loss) on restructuring and extinguishment of debt" in our Consolidated Statements of Operations for the year ended December 31, 2017.
The 1.75 Lien Term Loans are due on October 26, 2020, bear interest at a cash rate of
12.5%
per annum, or, if we elect to pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien Term Loans, at an interest rate of
15.0%
per annum. On September 20, 2017 we paid the interest due on the 1.75 Lien Term Loans in-kind with approximately
$26.2 million
of aggregate principal amount of 1.75 Lien Term Loans, resulting in
$708.9 million
of total aggregate principal amount of 1.75 Lien Term Loans outstanding. On December 19, 2017, we entered into a forbearance agreement with certain lenders under the 1.75 Lien Term Loans. Pursuant to this agreement, the lenders under the 1.75 Lien Term Loans agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement. The December 20, 2017 interest payment on the 1.75 Lien Term Loans was required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. We have not paid the interest on the 1.75 Lien Term Loans of
$27.0 million
, based on the rate of
15%
for PIK Payments that was due on December 20, 2017. Also, we have not paid the interest on the Second Lien Term Loans of
$0.5 million
that was due on December 26, 2017. As a result of the failure to pay interest on the Second Lien Term Loans, we are currently in default of the agreement governing the Second Lien Term Loans and the outstanding balance was classified as a current liability as of December 31, 2017.
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.
PIK Payments under the 1.5 Lien Notes and the 1.75 Lien Term Loans
The principal purpose of issuing the 1.5 Lien Notes and Second Lien Term Loan Exchange was to alleviate our substantial cash interest payment burden and improve our Liquidity. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow us to make payments in additional indebtedness or common shares ("PIK Payments"), subject to certain restrictions and limitations.
On June 20, 2017, we issued a total of
2,745,754
common shares ("PIK Shares") in lieu of an approximate
$23.0 million
cash interest payment under the 1.75 Lien Term Loans. The number of PIK Shares issued was calculated based on the interest rate for PIK Payments of
15.0%
, which resulted in a value of
$27.6 million
for the interest payment. The price of the Company's common shares for determining PIK Shares was based on the trailing
20
-day volume weighted average price calculated as of the end of the three trading days prior to February 28, 2017. On September 20, 2017, we paid approximately
$17.0 million
and
$26.2 million
of PIK Payments under the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans.
Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75 Lien Term Loans throughout the remainder of 2017 and 2018. However, there were significant limitations on our ability to make PIK Payments during 2017. Under our Registration Rights Agreement with the holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans ("Registration Rights Agreement"), our ability to make PIK Payments in common shares is subject to a resale registration statement related to the common shares issued as PIK Payments and all of the shares underlying the warrants issued in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans being declared effective by the SEC by October 11, 2017 ("Resale Registration Statement"). We did not anticipate the Resale Registration Statement would be declared effective as of October 11, 2017, and, as such, we provided a notice of a delay of effectiveness for the Resale Registration Statement to the
holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans, as permitted under the Registration Rights Agreement, extending the requirement for the Resale Registration Statement to be declared effective to no later than December 8, 2017. The Resale Registration Statement was not declared effective during 2017; therefore, we were restricted in making PIK Payments in common shares subsequent to December 8, 2017.
Even if the Resale Registration Statement was declared effective, the terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans prohibit the issuance of common shares as PIK Payments if it would result in a beneficial owner, directly or indirectly, owning more than 50% of our outstanding common shares. Our common share price experienced a significant decline during 2017, which would have resulted in the issuance of a greater number of common shares to make PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. This could have prevented us from being able to pay interest in common shares due to the 50% ownership limitation.
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
. This amount is reduced dollar-for-dollar to the extent that we incur any additional secured indebtedness, including PIK Payments in additional indebtedness. After the PIK Payments in additional indebtedness on September 20, 2017, our ability to make future PIK Payments in additional indebtedness was limited to
$6.9 million
. This would not have been sufficient to make our next quarterly interest payment of approximately
$26.9 million
, based on the PIK interest rate of
15.0%
on the 1.75 Lien Term Loans, that was scheduled to occur on December 20, 2017, and was required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. Furthermore, the agreement governing the 1.75 Lien Term Loans restricts our ability to pay interest in cash, unless we have liquidity, on a pro forma basis, of at least
$175.0 million
.
After December 31, 2018, the amount of PIK Payments we are permitted to make is dependent upon 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.
Covenants, events of default and other material provisions under the 1.5 Lien Notes and the 1.75 Lien Term Loans
The 1.5 Lien Notes and 1.75 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. The 1.5 Lien Notes and 1.75 Lien Term Loans are secured by second priority liens and third priority liens, respectively, on substantially all of EXCO’s assets and the assets of such guarantors. Subject to certain exceptions, the covenants under the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans limit our ability and the ability of our restricted subsidiaries to, among other things:
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•
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pay dividends or make other distributions or redeem or repurchase our common shares;
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•
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prepay, redeem or repurchase certain junior lien or unsecured debt;
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•
|
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;
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|
•
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engage in asset sales or substantially alter the business that we conduct;
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•
|
enter into transactions with affiliates;
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|
•
|
consolidate, merge or dispose of assets;
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|
•
|
enter into sale/leaseback transactions.
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In addition, the indenture governing the 1.5 Lien Notes includes restrictions on our ability to incur additional indebtedness, among other things and subject to certain restrictions. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans require that net cash proceeds of certain asset sales be used within one year to acquire or develop oil and natural gas properties or we must use the proceeds to permanently repay, redeem or repurchase a portion of the EXCO Resources Credit Agreement, 1.5 Lien Notes or 1.75 Lien Term Loans. If there is an event of default, we will be required to pay each of the 1.5 Lien Notes and the 1.75 Lien Term Loans in an amount equal to the outstanding principal amount plus an applicable make-whole premium.
In connection with the offering of the 1.5 Lien Notes and the Second Lien Term Loan Exchange, we entered into an amended and restated intercreditor agreement, under which the lenders of the remaining outstanding portion of the Exchange Term Loan agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes, the 1.75 Lien Term Loans and the lenders under EXCO Resources Credit Agreement. In addition, the lenders of the 1.75 Lien Term Loans agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes and the
lenders under the EXCO Resources Credit Agreement, and the holders of the 1.5 Lien Notes agreed to subordinate their security interest in the collateral to the lenders under the EXCO Resources Credit Agreement.
2018 Notes
The 2018 Notes are guaranteed on a senior unsecured basis by substantially all of EXCO’s subsidiaries. Our equity investments, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.
During 2015 and 2016, we completed exchanges and a series of open market repurchases of the 2018 Notes significantly reducing the aggregate principal amount outstanding. As of December 31, 2017,
$131.6 million
in principal was outstanding on the 2018 Notes. Interest accrues at
7.5%
per annum and is payable semi-annually in arrears on March 15 and September 15 of each year. The maturity date of the 2018 Notes is September 15, 2018.
The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:
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•
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incur or guarantee additional debt and issue certain types of preferred shares;
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•
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pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
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•
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make certain investments;
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•
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create liens on our assets;
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|
•
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enter into sale/leaseback transactions;
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•
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create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
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•
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engage in transactions with our affiliates;
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•
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transfer or issue shares of stock of subsidiaries;
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•
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transfer or sell assets; and
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•
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consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
|
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 and 2016, we completed exchanges and a series of open market repurchases of the 2022 Notes significantly reducing the aggregate principal amount outstanding. As of December 31, 2017,
$70.2 million
in principal was outstanding on the 2022 Notes.
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.
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6.
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Fair value measurements
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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.
During the years ended December 31, 2017 and 2016 there were no changes in the fair value level classifications, except that the Exchange Term Loan was reclassified to Level 3.
Fair value of derivative financial instruments
The following table presents a summary of the estimated fair value of our derivative financial instruments as of
December 31, 2017
and
2016
.
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December 31, 2017
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
1,150
|
|
|
$
|
—
|
|
|
$
|
1,150
|
|
Derivative financial instruments - common share warrants
|
|
—
|
|
|
(1,950
|
)
|
|
—
|
|
|
(1,950
|
)
|
|
|
December 31, 2016
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Derivative financial instruments - commodity derivatives
|
|
$
|
—
|
|
|
$
|
(27,693
|
)
|
|
$
|
—
|
|
|
$
|
(27,693
|
)
|
Derivative financial instruments - commodity derivatives
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 consisted of 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.
The fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers or sellers.
Derivative
financial
instruments - common share warrants
The liability attributable to our common share warrants as of the issuance date and the end of each reporting period was measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration.
See further details on 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 senior notes and term loans are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair value of the 1.5 Lien Notes, 1.75 Lien Term Loans and the Exchange Term Loan have been calculated based on quoted prices obtained from third-party pricing sources that lack significant observable inputs and are classified as Level 3. The 2017 Warrants are considered freestanding financial instruments and are not considered in the determination of the fair value of the 1.5 Lien Notes and 1.75 Lien Term Loans. The estimated fair value of the Exchange Term Loan was calculated based on quoted prices obtained from third-party sources and classified as Level 2 during 2016. During the year ended December 31, 2017, we reclassified the fair value of the Exchange Term Loan into Level 3 due to the lack of market activity and significant observable inputs. See "Note 5. Debt" for the carrying value and the principal balance of each debt instrument included in the table below.
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|
December 31, 2017
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
1.5 Lien Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
232,276
|
|
|
$
|
232,276
|
|
1.75 Lien Term Loans
|
|
—
|
|
|
—
|
|
|
372,186
|
|
|
372,186
|
|
Exchange Term Loan
|
|
—
|
|
|
—
|
|
|
9,054
|
|
|
9,054
|
|
2018 Notes
|
|
4,658
|
|
|
—
|
|
|
—
|
|
|
4,658
|
|
2022 Notes
|
|
2,586
|
|
|
—
|
|
|
—
|
|
|
2,586
|
|
|
|
December 31, 2016
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Exchange Term Loan
|
|
$
|
—
|
|
|
$
|
294,000
|
|
|
$
|
—
|
|
|
$
|
294,000
|
|
Fairfax Term Loan
|
|
—
|
|
|
222,000
|
|
|
—
|
|
|
222,000
|
|
2018 Notes
|
|
79,028
|
|
|
—
|
|
|
—
|
|
|
79,028
|
|
2022 Notes
|
|
35,260
|
|
|
—
|
|
|
—
|
|
|
35,260
|
|
Other fair value measurements
During 2017 and 2016, we impaired
$5.2 million
and
$4.9 million
, respectively, 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. During 2016, 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, 2017
. The commitments do not include those of our equity method investments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gathering and firm transportation services (1)
|
|
Other fixed commitments
|
|
Drilling contracts
|
|
Operating leases and other
|
|
Total
|
2018
|
|
$
|
87,621
|
|
|
$
|
3,222
|
|
|
$
|
1,138
|
|
|
$
|
3,760
|
|
|
$
|
95,741
|
|
2019
|
|
47,541
|
|
|
2,415
|
|
|
—
|
|
|
3,149
|
|
|
53,105
|
|
2020
|
|
46,463
|
|
|
1,949
|
|
|
—
|
|
|
1,622
|
|
|
50,034
|
|
2021
|
|
33,306
|
|
|
1,601
|
|
|
—
|
|
|
36
|
|
|
34,943
|
|
2022
|
|
33,306
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33,306
|
|
Thereafter
|
|
94,443
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
94,443
|
|
Total
|
|
$
|
342,680
|
|
|
$
|
9,187
|
|
|
$
|
1,138
|
|
|
$
|
8,567
|
|
|
$
|
361,572
|
|
|
|
(1)
|
The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regarding this agreement.
|
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, 2017
, our firm transportation and gathering agreements covered the following gross volumes of natural gas:
|
|
|
|
|
|
|
|
(in Bcf)
|
|
Firm transportation services (1)
|
|
Gathering services
|
2018
|
|
183
|
|
|
100
|
|
2019
|
|
183
|
|
|
—
|
|
2020
|
|
180
|
|
|
—
|
|
2021
|
|
146
|
|
|
—
|
|
2022
|
|
146
|
|
|
—
|
|
Thereafter
|
|
413
|
|
|
—
|
|
Total
|
|
1,251
|
|
|
100
|
|
|
|
(1)
|
The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regarding this agreement.
|
On January 18, 2018, the Company and the Filings Subsidiaries filed motions to reject certain executory contracts as permitted under the Bankruptcy Code. This included certain of our sales, gathering and transportation agreements included as commitments as of December 31, 2017. See further discussion of the rejection of these executory contracts in "Note 17. Subsequent events".
Enterprise and Acadian 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. EPD subsequently joined two of our officers, Harold Hickey and Steve Estes, asserting breach of fiduciary duty claims and thereafter joined Bluescape asserting tortious interference with an existing contract. We have filed a summary judgment motion as to the claims against us and our officers, and the motion is pending before the court. If we prevail on the summary judgment motion it could be case dispositive. This case is anticipated to go to trial in the second or third quarter of 2018; however, the case is stayed due to our Chapter 11 filings. 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, 2017, we recorded a net liability of
$43.8 million
for costs subsequent to the termination of the contract in accordance with the guidance related to contingencies in ASC 450. The minimum obligations under these agreements are included in the tables of our commercial commitments as of December 31, 2017.
Regency transportation agreement default
We have a firm transportation agreement with Regency Intrastate Gas Systems LLC ("Regency") to transport
237,500
Mmbtu/day of natural gas at a cost of
$0.30
per Mmbtu until January 31, 2020. We were obligated to pay a reservation charge of
$0.30
per Mmbtu if we failed to transport the minimum volumes under the agreement. The costs under the agreement were recorded as "Gathering and transportation expenses" in our Consolidated Statement of Operations.
On October 23, 2017, we were notified of our failure to pay
$2.2 million
for the July 2017 charges. The contract provides that the failure to pay the entire charge when due constitutes a default. If the payment default was not fully cured to Regency’s satisfaction within 30 days written notice, Regency has the right to immediately accelerate the payments of the remaining reservation charges due under the contract. We have not received a notice of acceleration. We have not cured the default for July 2017 and have not remitted payment for any subsequent months.
Due to our default under the contract and Regency's right to accelerate the remaining payments, we accounted for these contracts in accordance with ASC 450, which states that an estimated loss from a loss contingency shall be accrued if (1) information available before the financial statements are issued indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements, and (2) the amount of loss can be reasonably estimated. As of December 31, 2017, the unpaid amounts and remaining charges under this agreement of
$67.3 million
were recorded as "Revenue and royalties payable" in our Consolidated Balance Sheet. In addition to the expenses under the agreement prior to the event of default, we recorded
$56.4 million
related to the acceleration of the remaining charges subsequent to the event of default as "Other operating items" in our Consolidated Statement of Operations for the year ended December 31, 2017.
Shell natural gas sales contract litigation
We had a natural gas sales agreement with Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, under which we were contractually obligated to deliver and sell to Shell Energy, and Shell Energy was contractually obligated to receive and purchase from us, natural gas production of
100,000
Mmbtu/day. We were to receive the product of an index price and the volumes delivered less the product of the reservation charge of
$0.39
per Mmbtu and the daily contract volume. The contract was scheduled to end in November 2020.
On December 22, 2017, we received notice from Shell Energy that they were exercising their right to require adequate assurance of performance from us for the reservation charges under the contract. Shell Energy requested assurances in the form of letters of credit of approximately
$44.4 million
, which was approximately equal to the remaining reservation charges for the remaining term of the contract. We responded to the notice by stating the request for the letter of credit request was unreasonable and unjustified under the terms of the agreement. Subsequently, Shell Energy notified us that they were withholding payment for the purchase of natural gas for the months of November and December 2017 as a means to satisfy their demands of reasonable assurance of performance. Shell Energy allegedly terminated the sales contracts on December 26, 2017 as a result of the adequate assurance provision despite our objections to the reasonableness of their request. We ceased selling natural gas to Shell Energy in the East Texas and North Louisiana regions effective as of the date of their breach.
On December 26, 2017, we filed a claim in Harris County, Texas seeking declaratory relief that (1) we had not undergone an event of default as defined within the agreement, (2) Shell Energy was in material breach of the contract, and (3) Shell Energy’s request of adequate assurance of performance was neither reasonable, nor justified, and not in good faith under the agreement or applicable Texas law. In addition to the preceding, we are also seeking actual damages, reasonable attorneys’ fees, court costs, prejudgment and post-judgment interest at the maximum rate allowed by Texas law, and all other relief to which we may be justly entitled. On January 26, 2018, we filed a notice of non-suit in Harris County District Court. Concurrently with filing the notice of non-suit in the county court, we filed an adversary proceeding against Shell Energy in the Chapter 11 Cases.
As of December 31, 2017, we recorded a receivable of approximately
$33.4 million
related to the sales of natural gas to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. As of December 31, 2017, we are withholding
$16.8 million
in revenues payable to Shell to offset our exposure until the litigation is resolved. The revenues payable may increase in subsequent months due to the natural gas marketed on behalf of Shell's ownership interests in our operated wells. We plan to adamantly assert our right to terminate the contract as a result of Shell Energy's breach and
demand payment for the natural gas sales during November and December 2017. Due to the uncertainty surrounding the outcome of the litigation, we are not able to reasonably estimate a potential loss, if any, at this time. The minimum obligations under this agreement are included in the tables of our commercial commitments as of December 31, 2017.
Other commitments
We lease our offices and certain equipment. Our rental expenses were approximately
$2.3 million
,
$2.6 million
and
$3.4 million
for the years ended
December 31, 2017
,
2016
and
2015
, 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.
|
|
9.
|
Employee benefit plans
|
We sponsor a 401(k) plan for our employees and matched
100%
of employee contributions during 2015. 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 matched
100%
of employee contributions up to a maximum of
3%
of each employee's pay. Effective January 1, 2018, the Company increased its matching contribution up to a maximum of
4%
of each employee's pay. Our matching contributions were
$0.6 million
and
$5.2 million
for the years ended December 31,
2017
and
2015
, respectively.
The following table presents the basic and diluted earnings (loss) per share computations for the years ended
December 31, 2017
,
2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands, except per share data)
|
|
2017
|
|
2016
|
|
2015
|
Basic net income (loss) per common share:
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
24,362
|
|
|
$
|
(225,258
|
)
|
|
$
|
(1,192,381
|
)
|
Weighted average common shares outstanding
|
|
21,288
|
|
|
18,630
|
|
|
18,241
|
|
Net income (loss) per basic common share
|
|
$
|
1.14
|
|
|
$
|
(12.09
|
)
|
|
$
|
(65.37
|
)
|
Diluted net income (loss) per common share:
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
24,362
|
|
|
$
|
(225,258
|
)
|
|
$
|
(1,192,381
|
)
|
Weighted average common shares outstanding
|
|
21,288
|
|
|
18,630
|
|
|
18,241
|
|
Dilutive effect of:
|
|
|
|
|
|
|
Stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted shares and restricted share units
|
|
—
|
|
|
—
|
|
|
—
|
|
Warrants
|
|
—
|
|
|
—
|
|
|
—
|
|
Weighted average common shares and common share equivalents outstanding
|
|
21,288
|
|
|
18,630
|
|
|
18,241
|
|
Net income (loss) per diluted common share
|
|
$
|
1.14
|
|
|
$
|
(12.09
|
)
|
|
$
|
(65.37
|
)
|
Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, the Commitment Fee and Amendment Fee Warrants, which represent the right to purchase our common shares at an exercise price of
$0.01
, are included in our weighted average common shares outstanding and used in the
computation of our basic net income (loss) per common share. On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the Commitment Fee and Amendment Fee Warrants at an exercise price of
$0.01
. See "Note 13. Related party transactions" for additional information on the warrants issued to Fairfax.
Diluted net income (loss) per common share for years
December 31, 2017
, 2016 and 2015 is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards, Financing Warrants, and ESAS Warrants, whether exercisable or not. The computation of diluted EPS excluded
12,907,872
;
5,097,538
; and
2,636,279
antidilutive common share equivalents for the years ended
December 31, 2017
,
2016
and
2015
, respectively. The antidilutive common share equivalents for the year ended
December 31, 2017
primarily related to the Financing Warrants. The antidilutive common share equivalents for the year ended December 31, 2016 and 2015 primarily related to the ESAS Warrants. On November 9, 2017, the ESAS Warrants were forfeited as a result of suspension of the services and investment agreement with ESAS. See "Note 11. Equity-based and other incentive-based compensation" for additional information on the warrants issued to ESAS.
On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the Commitment Fee, Amendment Fee and Financing Warrants. See "Note 13. Related party transactions" for additional information on the Financing Warrants issued to Fairfax.
11.
Equity-based and other incentive-based compensation
Share-based compensation
Description of plan
Our 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to
3,033,333
restricted shares, restricted share units and stock options. As of
December 31, 2017
and
2016
, there were
1,140,543
and
952,918
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.
We believe it is highly likely that our existing common shares and share-based compensation will be canceled at the conclusion of our Chapter 11 proceedings and holders will be entitled to a limited recovery, if any. See "Item 1A. Risk Factors" for additional information.
Stock options
As of December 31, 2017, we had
108,578
stock options outstanding and exercisable with exercise prices ranging from
$74.70
to
$405.00
per share. We did
no
t grant any stock options during the years ended December 31, 2017, 2016 or 2015. Our outstanding stock option expiration dates range from
five
to
ten
years following the date of grant and have a weighted average remaining life of
3.24
years.
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 year ended
December 31, 2017
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
|
Non-vested shares outstanding at December 31, 2016
|
|
145,907
|
|
|
$
|
18.99
|
|
|
Granted
|
|
39,384
|
|
|
9.78
|
|
|
Vested
|
|
(117,781
|
)
|
|
17.94
|
|
|
Forfeited
|
|
(30,908
|
)
|
|
15.10
|
|
|
Non-vested shares outstanding at December 31, 2017
|
|
36,602
|
|
|
$
|
15.75
|
|
Market-based restricted share awards
Certain RSU's granted to our officers and certain employees have vesting percentages between
0%
and
200%
depending on EXCO's total shareholder return in comparison to an identified peer group. Our market-based restricted share units are valued on the date of grant and vest over a range of
three
years, subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method.
The Company has discretion to convert certain vested awarded units, if any, into a cash payment equal to the fair market value of a share of common stock, multiplied by the number of vested units, or the number of whole shares of common stock equal to the number of vested units, if any. These RSUs met the criteria for equity classification per ASC 718.
The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. The assumptions used in the Monte Carlo model for the RSUs granted in 2016 are as follows:
|
|
|
|
Assumption
|
|
2016
|
Risk-free rate of return
|
|
0.45 - 0.71 %
|
Volatility
|
|
119.83 %
|
Dividend yield
|
|
0.00 %
|
A summary of our market-based restricted share activity for RSUs during the year ended
December 31, 2017
is as follows:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
|
|
Non-vested shares/units outstanding at December 31, 2016
|
|
337,331
|
|
|
$
|
27.83
|
|
Granted
|
|
—
|
|
|
—
|
|
Vested
|
|
—
|
|
|
—
|
|
Forfeited
|
|
(87,339
|
)
|
|
21.74
|
|
Non-vested shares/units outstanding at December 31, 2017
|
|
249,992
|
|
|
$
|
29.96
|
|
ESAS Warrants
On September 8, 2015, EXCO issued warrants to ESAS as an additional performance incentive for services performed under a services and investment agreement. The ESAS Warrants were issued in
four
tranches to purchase an aggregate of
5,333,335
common shares, subject to certain time-based vesting criteria and EXCO's total shareholder return in comparison to an identified peer group. See further discussion of the ESAS Warrants in "Note 13. Related party transactions".
Equity-based compensation costs
All of our stock options, restricted shares and certain RSUs are accounted for in accordance with ASC 718 and are classified as equity. As required by ASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital.
Total share-based compensation to employees to be recognized on unvested options, restricted share awards and RSUs as of
December 31, 2017
was
$3.2 million
and will be recognized over a weighted average period of
1.4
years.
The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the ESAS Warrants to be re-measured each interim reporting period and an adjustment was recorded in the statement of operations within equity-based compensation expense. Concurrently with the suspension of the services and investment agreement with ESAS, on November 9, 2017, the ESAS Warrants were forfeited and canceled and previously recognized compensation costs were reversed. For the years ended December 31, 2017, 2016 and 2015, equity-based compensation related to the ESAS Warrants was income of
$14.5 million
and expense of
$11.3 million
and
$3.2 million
, respectively.
The following is a reconciliation of our compensation expense for the years ended
December 31, 2017
,
2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Equity-based compensation expense (1)
|
|
$
|
(11,430
|
)
|
|
$
|
14,778
|
|
|
$
|
7,198
|
|
Equity-based compensation capitalized
|
|
1,000
|
|
|
752
|
|
|
3,428
|
|
Total equity-based compensation
|
|
$
|
(10,430
|
)
|
|
$
|
15,530
|
|
|
$
|
10,626
|
|
|
|
(1)
|
Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for ESAS Warrants.
|
We did
no
t recognize a tax benefit attributable to our equity-based compensation for the years ended December 31, 2017, 2016 and 2015.
Key Employee Incentive Plan, Key Employee Retention Plan, and Prepaid Retention Plans
In connection with our review of strategic alternatives during late 2017, the Compensation Committee of the Board of Directors (“Compensation Committee”) determined that (i) normal annual and long-term incentive cycles are likely to be ineffective due to our ongoing strategic restructuring efforts and (ii) the use of equity compensation is currently ineffective and inefficient. As a result, the Compensation Committee and the Company restructured our incentive plans to retain employees and align the interests of employees with our stakeholders. We implemented the following changes to our compensation plans:
|
|
•
|
Termination of the 2017 Management Incentive Plan
- We terminated the 2017 Management Incentive Plan and made pro-rated incentive payments based on the achievement of performance goals as of June 30, 2017. The payments of
$1.1 million
were made in cash.
|
|
|
•
|
Adoption of the KEIP and KERP
- We adopted
two
new cash-based incentive programs, including the Key Employee Incentive Plan ("KEIP") for certain officers and Key Employee Retention Plan ("KERP") for employees. The payout of the KEIP is dependent on the achievement of certain performance goals, including production, general and administrative expenses, lease operating expenses, and EBITDA. The payout of the KERP was dependent on the achievement of these performance measures and a fixed percentage of the employees' salary for the first two quarters of the plan until it was converted to be solely based on a fixed percentage of the employees' salary. The initial term under each of these plans is from July 1, 2017 to June 30, 2018. We incurred
$4.8 million
in general and administrative expenses related to these plans during 2017. The motion to consider the KERP was approved by the Court on February 22, 2018. The approval of the KEIP for the period subsequent to the petition date remains subject to approval as part of the Chapter 11 Cases. As a result, the terms and amounts related to the KEIP could materially change if we receive objections from the Court or our creditors. The KEIP and KERP may be extended beyond the initial term at the discretion of the Compensation Committee or the Company, which would be subject to further approval as part of the Chapter 11 Cases.
|
|
|
•
|
Retention Bonus Agreements
- We entered into retention bonus agreements with certain key officers and employees, which resulted in payments of
$7.9 million
during 2017. In the event a recipient of a retention bonus voluntarily terminates his or her employment without Good Reason (as defined in each Retention Bonus Agreement), or the Company terminates such recipient’s employment for Cause (as defined in each Retention Bonus Agreement), in either case, before either December 31, 2018 or March 31, 2019 (depending on the agreement with the officer or employee), then such recipient will be required to promptly repay the retention bonus. We recognized
$1.4 million
of general and administrative expenses related to these retention bonuses during 2017 and the remainder will be recognized over the remaining retention period.
|
|
|
•
|
Discontinuation of equity incentive grants
- We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there were no grants of share-based compensation during 2017. The adoption of the KEIP, KERP and retention bonuses were intended to replace all existing cash-based bonus and equity-based compensation programs.
|
The income tax provision attributable to our income (loss) before income taxes for the years ended December 31,
2017
,
2016
and
2015
, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
(in thousands)
|
|
2017
|
|
2016 (1)
|
|
2015
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
(1,420
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
—
|
|
|
—
|
|
|
—
|
|
Total current income tax (benefit)
|
|
$
|
(1,420
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
|
$
|
528,886
|
|
|
$
|
(72,020
|
)
|
|
$
|
(414,834
|
)
|
State
|
|
(1,496
|
)
|
|
(7,637
|
)
|
|
(45,009
|
)
|
Valuation allowance
|
|
(525,674
|
)
|
|
82,459
|
|
|
459,843
|
|
Total deferred income tax (benefit)
|
|
1,716
|
|
|
2,802
|
|
|
—
|
|
Total income tax (benefit)
|
|
$
|
296
|
|
|
$
|
2,802
|
|
|
$
|
—
|
|
|
|
(1)
|
We made certain revisions between components of the reconciliation of our income tax provision for the year ended December 31, 2016. These revisions were deemed to be an immaterial correction of an error and did not affect our net deferred tax assets or liabilities or income tax expense.
|
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Act") which, among other things, lowered the U.S. Federal tax rate from
35%
to
21%
, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We reflected the impact of this rate on our deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. We have credits that are expected to be refunded between 2018 and 2020 as a result of the Tax Act and monetization opportunities under current law in 2017. In addition, the Tax Act limits the amount taxpayers are able to deduct for net operating loss carryforwards ("NOLs") generated in taxable years beginning after December 31, 2017 to
80%
of the taxpayer’s taxable income. The law also generally repeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending after December 31, 2017 can be carried forward indefinitely. On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides a one-year measurement period from a registrant's reporting period that includes the Tax Act's enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.
We have NOLs for U.S. income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between 2028 and 2037. 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
$86.6 million
,
$125.8 million
and
$538.0 million
during 2017, 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. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one or more five-percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing date within a three-year period. See further discussion of the potential limitations on the utilization of our net operating losses as part of "Item 1A. Risk Factors". The Internal Revenue Code permits the exclusion of cancellation of debt income from taxable income if the discharge occurs during a Chapter 11 case. If this occurs, the amount of cancellation of debt income would reduce a company's tax attributes unless it is offset by NOLs. The NOLs that are available to offset cancellation of debt income in a Chapter 11 case are not limited by
Section 382 of the Internal Revenue Code. NOLs available for utilization as of
December 31, 2017
were approximately
$2.1 billion
.
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, 2017
|
|
December 31, 2016 (1)
|
Deferred tax assets:
|
|
|
|
|
Net operating loss and AMT credits carryforwards
|
|
$
|
548,701
|
|
|
$
|
767,236
|
|
Oil and natural gas properties, gathering assets, and equipment
|
|
236,601
|
|
|
428,056
|
|
Debt restructuring
|
|
3,978
|
|
|
99,934
|
|
Other
|
|
54,487
|
|
|
73,923
|
|
Total deferred tax assets before valuation allowance
|
|
843,767
|
|
|
1,369,149
|
|
Valuation allowance
|
|
(843,480
|
)
|
|
(1,369,149
|
)
|
Total deferred tax assets
|
|
287
|
|
|
—
|
|
Deferred tax liabilities:
|
|
|
|
|
Goodwill
|
|
$
|
(4,518
|
)
|
|
$
|
(2,802
|
)
|
Derivative financial instruments
|
|
(287
|
)
|
|
—
|
|
Total deferred tax liabilities
|
|
(4,805
|
)
|
|
(2,802
|
)
|
Net deferred tax assets (liabilities)
|
|
$
|
(4,518
|
)
|
|
$
|
(2,802
|
)
|
|
|
(1)
|
We made certain revisions between components of our non-current deferred tax assets as of December 31, 2016. As a result, our deferred tax assets and valuation allowance increased by
$0.8 million
. These revisions were deemed to be an immaterial correction of an error and did not affect our net deferred tax assets or liabilities or income tax expense.
|
As previously discussed, we reflected the impact of the change in the tax rate as a result of the Tax Act on our deferred tax assets and liabilities at December 31, 2017. During the years ended 2017, 2016 and
2015
, we recognized a full valuation allowance against our net deferred tax assets.
A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended
December 31, 2017
,
2016
and
2015
is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016 (1)
|
|
2015
|
Federal income taxes (benefit) provision at statutory rate of 35%
|
|
$
|
8,630
|
|
|
$
|
(77,860
|
)
|
|
$
|
(417,333
|
)
|
Increases (reductions) resulting from:
|
|
|
|
|
|
|
Adjustments to the valuation allowance
|
|
(525,674
|
)
|
|
82,459
|
|
|
459,843
|
|
Non-deductible compensation
|
|
3,206
|
|
|
5,019
|
|
|
2,399
|
|
State taxes net of federal benefit
|
|
(1,496
|
)
|
|
(7,637
|
)
|
|
(45,009
|
)
|
Federal and state tax rate change
|
|
421,610
|
|
|
—
|
|
|
—
|
|
Non-deductible interest
|
|
149,577
|
|
|
—
|
|
|
—
|
|
Non-taxable gain on warrants
|
|
(55,716
|
)
|
|
—
|
|
|
—
|
|
Other
|
|
159
|
|
|
821
|
|
|
100
|
|
Total income tax provision
|
|
$
|
296
|
|
|
$
|
2,802
|
|
|
$
|
—
|
|
|
|
(1)
|
We made certain revisions between components of the reconciliation of our income tax provision for the year ended December 31, 2016. These revisions were deemed to be an immaterial correction of an error and did not affect our net deferred tax assets or liabilities or income tax expense.
|
During the year ended December 31, 2017, we recognized a current income tax benefit of
$1.4 million
due to refunds for alternative minimum tax credits. During the years ended
2017
and 2016, we recognized deferred income tax expense of
$1.7
million
and
$2.8 million
related to a deferred tax liability for tax deductible goodwill. During the years ended
2017
and 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.
We did not recognize any liabilities for unrecognized tax benefits. As of December 31,
2017
,
2016
and
2015
, our policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. We have not accrued any interest or penalties relating to unrecognized tax benefits in the Consolidated Financial Statements.
We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax returns in various states. With few exceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2008.
|
|
13.
|
Related party transactions
|
OPCO and Appalachia Midstream JV
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, 2017
,
2016
or
2015
. 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, 2017
,
2016
and
2015
these transactions included the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Amounts received from OPCO
|
|
6,596
|
|
|
15,016
|
|
|
30,577
|
|
As of
December 31, 2017
and
2016
, the amounts owed under the service agreements were as follows:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2017
|
|
December 31, 2016
|
Amounts due to EXCO (1)
|
|
$
|
587
|
|
|
$
|
618
|
|
Amounts due from EXCO (2)
|
|
3,726
|
|
|
13,624
|
|
|
|
(1)
|
Amounts due to us consist of receivables for services performed on behalf of OPCO. These amounts are recorded in "Accounts receivable, net — Other" on our Consolidated Balance Sheets.
|
|
|
(2)
|
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.
|
As of December 31, 2017, we owned a
50%
interest in an entity that owns and operates midstream assets in the Appalachia region ("Appalachia Midstream JV"). On October 12, 2017, EXCO received a
$6.0 million
cash distribution from Appalachia Midstream JV.
ESAS
On March 31, 2015, we entered into a services and investment agreement with ESAS, a wholly owned subsidiary of an affiliate of Bluescape. C. John Wilder, Executive Chairman of Bluescape, was the Executive Chairman of our Board of Directors until his resignation on November 9, 2017, and indirectly controls ESAS. As consideration for the services provided under the agreement, EXCO paid ESAS a monthly fee of
$300,000
and an annual incentive payment of up to
$2.4 million
per year that was based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group. 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. As an additional performance incentive under the services and investment agreement, EXCO issued ESAS Warrants in
four
tranches to purchase an aggregate of
5,333,335
common shares, subject to the satisfaction of certain performance criteria, at exercise prices ranging from
$41.25
per share to
$150.00
per share. The number of shares and exercise prices have been adjusted to reflect the reverse share-split that occurred on June 2, 2017.
The payments to ESAS as part of the services and investment agreement were
$3.4 million
and
$8.4 million
during 2017 and 2016, respectively. Amounts paid to ESAS in 2017 consisted of the monthly fees through the suspension of the contract in November 9, 2017. 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.
On September 20, 2017, ESAS received
$4.0 million
and
$1.8 million
of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in ESAS holding
$74.0 million
in aggregate principal amount of 1.5 Lien Notes and
$49.7 million
in aggregate principal amount of 1.75 Lien Term Loans as of December 31, 2017. During the year ended December 31, 2017, ESAS also received
$1.2 million
of cash interest payments on the Exchange Term Loan and
192,609
of PIK Shares under the 1.75 Lien Term Loans. In addition, ESAS holds Financing Warrants representing the right to purchase an aggregate of
5,017,922
common shares at an exercise price equal to
$13.95
per share. ESAS received a consent fee of
$1.6 million
in cash for exchanging its interest in the Exchange Term Loan, and a commitment fee of
$2.1 million
in cash in connection with the issuance of the 1.5 Lien Notes.
On November 9, 2017, we entered into an agreement with ESAS pursuant to which, among other things: (i) the services and investment agreement with ESAS, dated as of March 31, 2015, was suspended such that, during the suspension period and subject to the terms and conditions of the agreement: (a) ESAS is not required to provide any services to us, (b) we are not required to make any payments to ESAS with respect to the suspension period and (c) ESAS does not have the right to nominate a member to the Company’s Board of Directors; and (ii) the ESAS Warrants were forfeited and canceled and we have no further obligations under the ESAS Warrants.
On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Bluescape. See "Note 17. Subsequent events" further discussion of the DIP Credit Agreement.
Fairfax
Samuel Mitchell serves as a Managing Director of Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa"), the investment manager of Fairfax and certain affiliates thereof. Samuel Mitchell was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, certain affiliates of Fairfax received
$8.5 million
and
$15.8 million
of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in Fairfax holding, directly or indirectly,
$159.5 million
in aggregate principal amount of 1.5 Lien Notes and
$427.9 million
in aggregate principal amount of 1.75 Lien Term Loans as of
December 31, 2017
. During the year ended
December 31, 2017
, Fairfax also received
$10.6 million
of cash interest payments on the Fairfax Term Loan and the Exchange Term Loan and
1,657,330
of PIK Shares under the 1.75 Lien Term Loans. In addition, Fairfax holds Financing Warrants representing the right to purchase an aggregate of
10,824,377
common shares at an exercise price equal to
$13.95
per share, Commitment Fee Warrants representing the right to purchase an aggregate of
431,433
common shares at an exercise price equal to
$0.01
per share and Amendment Fee Warrants representing the right to purchase an aggregate of
1,294,143
common shares at an exercise price equal to
$0.01
per share. On January 16, 2018, affiliates of Fairfax surrendered all of their rights in the 2017 Warrants.
On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax. See "Note 17. Subsequent events" further discussion of the DIP Credit Agreement.
Oaktree
B. James Ford serves as a Senior Advisor of Oaktree, and was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, Oaktree received
$2.2 million
of PIK Payments in the form of additional 1.5 Lien Notes resulting in certain affiliates of Oaktree holding, directly or indirectly,
$41.7 million
in aggregate principal amount of 1.5 Lien Notes as of
December 31, 2017
. In addition, certain affiliates of Oaktree hold Financing Warrants representing the right to purchase an aggregate of
2,831,542
common shares at an exercise price equal to
$13.95
per share. Oaktree also received a commitment fee of
$1.2 million
in cash in connection with the issuance of the 1.5 Lien Notes.
|
|
14.
|
Condensed consolidating financial statements
|
As of
December 31, 2017
, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit agreement governing the 1.75 Lien Term Loans, the credit agreement governing the Second Lien Term Loans, and the indentures governing the 2018 Notes and 2022 Notes. The DIP Credit Agreement, entered into on January 22, 2018, is guaranteed by the same subsidiaries as the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes. All of our unrestricted subsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries.
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, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
49,170
|
|
|
$
|
(9,573
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
39,597
|
|
Restricted cash
|
|
—
|
|
|
15,271
|
|
|
—
|
|
|
—
|
|
|
15,271
|
|
Other current assets
|
|
22,697
|
|
|
90,265
|
|
|
—
|
|
|
—
|
|
|
112,962
|
|
Total current assets
|
|
71,867
|
|
|
95,963
|
|
|
—
|
|
|
—
|
|
|
167,830
|
|
Equity investments
|
|
—
|
|
|
—
|
|
|
14,181
|
|
|
—
|
|
|
14,181
|
|
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
118,652
|
|
|
—
|
|
|
—
|
|
|
118,652
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
333,719
|
|
|
2,773,847
|
|
|
—
|
|
|
—
|
|
|
3,107,566
|
|
Accumulated depletion
|
|
(330,777
|
)
|
|
(2,421,534
|
)
|
|
—
|
|
|
—
|
|
|
(2,752,311
|
)
|
Oil and natural gas properties, net
|
|
2,942
|
|
|
470,965
|
|
|
—
|
|
|
—
|
|
|
473,907
|
|
Other property and equipment, net and other non-current assets
|
|
892
|
|
|
20,382
|
|
|
—
|
|
|
—
|
|
|
21,274
|
|
Investments in and advances to affiliates, net
|
|
466,055
|
|
|
—
|
|
|
—
|
|
|
(466,055
|
)
|
|
—
|
|
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
Total assets
|
|
$
|
555,049
|
|
|
$
|
737,172
|
|
|
$
|
14,181
|
|
|
$
|
(466,055
|
)
|
|
$
|
840,347
|
|
Liabilities and shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
1,362,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,362,500
|
|
Other current liabilities
|
|
32,280
|
|
|
272,190
|
|
|
—
|
|
|
—
|
|
|
304,470
|
|
Long-term debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Derivative financial instruments - common share warrants
|
|
1,950
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,950
|
|
Other long-term liabilities
|
|
4,518
|
|
|
13,108
|
|
|
—
|
|
|
—
|
|
|
17,626
|
|
Payable to parent
|
|
—
|
|
|
2,447,586
|
|
|
—
|
|
|
(2,447,586
|
)
|
|
—
|
|
Total shareholders' equity
|
|
(846,199
|
)
|
|
(1,995,712
|
)
|
|
14,181
|
|
|
1,981,531
|
|
|
(846,199
|
)
|
Total liabilities and shareholders' equity
|
|
$
|
555,049
|
|
|
$
|
737,172
|
|
|
$
|
14,181
|
|
|
$
|
(466,055
|
)
|
|
$
|
840,347
|
|
EXCO RESOURCES, INC.
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 and other non-current assets
|
|
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 - commodity derivatives
|
|
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 maturities of long-term debt
|
|
$
|
50,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50,000
|
|
Other current liabilities
|
|
40,671
|
|
|
167,692
|
|
|
—
|
|
|
—
|
|
|
208,363
|
|
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 STATEMENT OF OPERATIONS
For the year ended
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
—
|
|
|
$
|
258,830
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
258,830
|
|
Purchased natural gas and marketing
|
|
—
|
|
|
24,816
|
|
|
—
|
|
|
—
|
|
|
24,816
|
|
Total revenues
|
|
—
|
|
|
283,646
|
|
|
—
|
|
|
—
|
|
|
283,646
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
—
|
|
|
48,142
|
|
|
—
|
|
|
—
|
|
|
48,142
|
|
Gathering and transportation
|
|
—
|
|
|
111,427
|
|
|
—
|
|
|
—
|
|
|
111,427
|
|
Purchased natural gas
|
|
—
|
|
|
23,400
|
|
|
—
|
|
|
—
|
|
|
23,400
|
|
Depletion, depreciation and amortization
|
|
298
|
|
|
50,742
|
|
|
—
|
|
|
—
|
|
|
51,040
|
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Accretion of discount on asset retirement obligations
|
|
—
|
|
|
874
|
|
|
—
|
|
|
—
|
|
|
874
|
|
General and administrative
|
|
(30,224
|
)
|
|
60,389
|
|
|
—
|
|
|
—
|
|
|
30,165
|
|
Other operating items
|
|
553
|
|
|
58,601
|
|
|
—
|
|
|
—
|
|
|
59,154
|
|
Total costs and expenses
|
|
(29,373
|
)
|
|
353,575
|
|
|
—
|
|
|
—
|
|
|
324,202
|
|
Operating income (loss)
|
|
29,373
|
|
|
(69,929
|
)
|
|
—
|
|
|
—
|
|
|
(40,556
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(108,173
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(108,175
|
)
|
Gain on derivative financial instruments - commodity derivatives
|
|
24,732
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,732
|
|
Gain on derivative financial instruments - common share warrants
|
|
159,190
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
159,190
|
|
Loss on restructuring of debt
|
|
(6,380
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,380
|
)
|
Other income
|
|
30
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
31
|
|
Equity loss
|
|
—
|
|
|
—
|
|
|
(4,184
|
)
|
|
—
|
|
|
(4,184
|
)
|
Net loss from consolidated subsidiaries
|
|
(74,114
|
)
|
|
—
|
|
|
—
|
|
|
74,114
|
|
|
—
|
|
Total other income (expense)
|
|
(4,715
|
)
|
|
(1
|
)
|
|
(4,184
|
)
|
|
74,114
|
|
|
65,214
|
|
Income (loss) before income taxes
|
|
24,658
|
|
|
(69,930
|
)
|
|
(4,184
|
)
|
|
74,114
|
|
|
24,658
|
|
Income tax expense
|
|
296
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
296
|
|
Net income (loss)
|
|
$
|
24,362
|
|
|
$
|
(69,930
|
)
|
|
$
|
(4,184
|
)
|
|
$
|
74,114
|
|
|
$
|
24,362
|
|
EXCO RESOURCES, INC.
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 - commodity derivatives
|
|
(34,137
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,137
|
)
|
Gain on restructuring and 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
|
)
|
Income (loss) before income taxes
|
|
(222,456
|
)
|
|
(231,331
|
)
|
|
(16,432
|
)
|
|
247,763
|
|
|
(222,456
|
)
|
Income tax expense
|
|
2,802
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,802
|
|
Net income (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 - commodity derivative
|
|
75,869
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75,869
|
|
Gain on restructuring 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
|
|
Income (loss) before income taxes
|
|
(1,192,381
|
)
|
|
(1,332,211
|
)
|
|
(15,691
|
)
|
|
1,347,902
|
|
|
(1,192,381
|
)
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income (loss)
|
|
$
|
(1,192,381
|
)
|
|
$
|
(1,332,211
|
)
|
|
$
|
(15,691
|
)
|
|
$
|
1,347,902
|
|
|
$
|
(1,192,381
|
)
|
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(22,761
|
)
|
|
$
|
77,172
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
54,411
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(1,347
|
)
|
|
(169,820
|
)
|
|
—
|
|
|
—
|
|
|
(171,167
|
)
|
Proceeds from disposition of property and equipment
|
|
—
|
|
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
Restricted cash
|
|
—
|
|
|
(4,121
|
)
|
|
—
|
|
|
—
|
|
|
(4,121
|
)
|
Net changes in advances to joint ventures
|
|
—
|
|
|
(9,161
|
)
|
|
—
|
|
|
—
|
|
|
(9,161
|
)
|
Equity investments and other
|
|
—
|
|
|
1,548
|
|
|
—
|
|
|
—
|
|
|
1,548
|
|
Advances/investments with affiliates
|
|
(110,001
|
)
|
|
110,001
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net cash used in investing activities
|
|
(111,348
|
)
|
|
(71,203
|
)
|
|
—
|
|
|
—
|
|
|
(182,551
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under EXCO Resources Credit Agreement
|
|
163,401
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
163,401
|
|
Repayments under EXCO Resources Credit Agreement
|
|
(265,592
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265,592
|
)
|
Proceeds received from issuance of 1.5 Lien Notes
|
|
295,530
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
295,530
|
|
Payments on Exchange Term Loan
|
|
(11,602
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,602
|
)
|
Payments of common share dividends
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Debt financing costs and other
|
|
(23,062
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23,062
|
)
|
Net cash provided by financing activities
|
|
158,669
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
158,669
|
|
Net increase (decrease) in cash
|
|
24,560
|
|
|
5,969
|
|
|
—
|
|
|
—
|
|
|
30,529
|
|
Cash at beginning of period
|
|
24,610
|
|
|
(15,542
|
)
|
|
—
|
|
|
—
|
|
|
9,068
|
|
Cash at end of period
|
|
$
|
49,170
|
|
|
$
|
(9,573
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
39,597
|
|
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 EXCO Resources Credit Agreement
|
|
404,897
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
404,897
|
|
Repayments under EXCO Resources Credit Agreement
|
|
(243,797
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(243,797
|
)
|
Repurchases of senior unsecured notes
|
|
(53,298
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(53,298
|
)
|
Payment 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
|
|
(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 EXCO Resources Credit Agreement
|
|
165,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
165,000
|
|
Repayments under EXCO Resources Credit Agreement
|
|
(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 provided by 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
|
|
|
|
15.
|
Quarterly financial data (unaudited)
|
The following are summarized quarterly financial data for the years ended
December 31, 2017
and
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
(in thousands, except per share amounts)
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
2017
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
76,529
|
|
|
$
|
71,015
|
|
|
$
|
66,736
|
|
|
$
|
69,366
|
|
Operating income (loss) (1)
|
|
13,587
|
|
|
15,216
|
|
|
(5,142
|
)
|
|
(64,217
|
)
|
Net income (loss) (2)
|
|
$
|
8,193
|
|
|
$
|
120,750
|
|
|
$
|
(18,824
|
)
|
|
$
|
(85,757
|
)
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.44
|
|
|
$
|
6.13
|
|
|
$
|
(0.81
|
)
|
|
$
|
(3.68
|
)
|
Weighted average shares
|
|
18,726
|
|
|
19,702
|
|
|
23,319
|
|
|
23,333
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.44
|
|
|
$
|
6.07
|
|
|
$
|
(0.81
|
)
|
|
$
|
(3.68
|
)
|
Weighted average shares
|
|
18,749
|
|
|
19,886
|
|
|
23,319
|
|
|
23,333
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
56,090
|
|
|
$
|
58,791
|
|
|
$
|
77,186
|
|
|
$
|
78,934
|
|
Operating income (loss) (3)
|
|
(164,698
|
)
|
|
(72,997
|
)
|
|
4,142
|
|
|
12,604
|
|
Net income (loss) (4)
|
|
$
|
(130,148
|
)
|
|
$
|
(111,347
|
)
|
|
$
|
50,936
|
|
|
$
|
(34,699
|
)
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(7.01
|
)
|
|
$
|
(5.99
|
)
|
|
$
|
2.73
|
|
|
$
|
(1.86
|
)
|
Weighted average shares
|
|
18,568
|
|
|
18,597
|
|
|
18,670
|
|
|
18,686
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(7.01
|
)
|
|
$
|
(5.99
|
)
|
|
$
|
2.72
|
|
|
$
|
(1.86
|
)
|
Weighted average shares
|
|
18,568
|
|
|
18,597
|
|
|
18,749
|
|
|
18,686
|
|
|
|
(
1)
|
Operating loss for the fourth quarter of 2017 includes the acceleration of the remaining charges under a firm transportation agreement of
$56.4 million
. See "Note 8. Commitments and contingencies" for further discussion.
|
|
|
(2)
|
Net income (loss) includes gains on the revaluation of the 2017 Warrants of
$6.0 million
,
$122.3 million
,
$18.3 million
and
$12.6 million
during the first, second, third, and fourth quarters of 2017, respectively, primarily due to a decrease in EXCO's share price. See "Note 4. Derivative financial instruments" for further discussion.
|
|
|
(3)
|
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.
|
|
|
(4)
|
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.
|
|
|
16.
|
Supplemental information relating to oil and natural gas producing activities (unaudited)
|
The following supplemental information relating to our oil and natural gas producing activities for the years ended
December 31, 2017
,
2016
and
2015
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
|
2017:
|
|
|
Proved property acquisition costs
|
|
$
|
18,940
|
|
Unproved property acquisition costs
|
|
5,228
|
|
Total property acquisition costs
|
|
24,168
|
|
Development
|
|
128,323
|
|
Exploration costs (1)
|
|
19,538
|
|
Lease acquisitions and other
|
|
5,654
|
|
Capitalized asset retirement costs
|
|
12
|
|
Depletion per Boe
|
|
$
|
3.45
|
|
Depletion per Mcfe
|
|
$
|
0.57
|
|
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
|
|
|
|
(1)
|
Exploration costs in 2017 related to the wells drilled in the Bossier shale in North Louisiana. Exploration costs in 2015 related to the wells drilled in the Buda formation in South Texas.
|
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 (8)
|
December 31, 2014
|
|
17,687
|
|
|
1,157,674
|
|
|
1,263,796
|
|
Purchase of reserves in place (1)
|
|
459
|
|
|
122
|
|
|
2,876
|
|
Discoveries and extensions (2)
|
|
7,602
|
|
|
152,473
|
|
|
198,085
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
Changes in price
|
|
(2,821
|
)
|
|
(598,865
|
)
|
|
(615,791
|
)
|
Other factors (3)
|
|
(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 (4)
|
|
—
|
|
|
16,381
|
|
|
16,381
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
Changes in price
|
|
(2,061
|
)
|
|
(55,748
|
)
|
|
(68,114
|
)
|
Other factors (5)
|
|
(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
|
|
Purchase of reserves in place (6)
|
|
—
|
|
|
50,456
|
|
|
50,456
|
|
Discoveries and extensions
|
|
13
|
|
|
21,880
|
|
|
21,958
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
Changes in price
|
|
679
|
|
|
30,200
|
|
|
34,274
|
|
Other factors (7)
|
|
(290
|
)
|
|
72,332
|
|
|
70,593
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
|
(1,158
|
)
|
|
(80,136
|
)
|
|
(87,084
|
)
|
December 31, 2017
|
|
9,412
|
|
|
510,451
|
|
|
566,924
|
|
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls)
|
|
Natural
Gas
(Mmcf)
|
|
Mmcfe
|
Proved developed:
|
|
|
|
|
|
|
December 31, 2017
|
|
9,412
|
|
|
510,451
|
|
|
566,924
|
|
December 31, 2016
|
|
10,168
|
|
|
415,719
|
|
|
476,727
|
|
December 31, 2015
|
|
12,056
|
|
|
364,932
|
|
|
437,268
|
|
Proved undeveloped:
|
|
|
|
|
|
|
December 31, 2017
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2015
|
|
8,383
|
|
|
419,742
|
|
|
470,040
|
|
|
|
(1)
|
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.
|
|
|
(2)
|
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.
|
|
|
(3)
|
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.
|
|
|
(4)
|
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.
|
|
|
(5)
|
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.
|
|
|
(6)
|
Purchases of reserves in place primarily related to the acquisition of incremental interests in certain oil and natural gas properties that we operate and undeveloped acreage in the North Louisiana region.
|
|
|
(7)
|
Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2017 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana region.
|
|
|
(8)
|
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, the ability to demonstrate the financing available to fund a development program with Reasonable Certainty could have a significant impact on our Proved Undeveloped Reserves. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends.
|
|
|
|
|
|
(in thousands)
|
|
Amount
|
Year ended December 31, 2017:
|
|
|
Future cash inflows
|
|
$
|
1,690,056
|
|
Future production costs
|
|
863,847
|
|
Future development costs (1)
|
|
51,925
|
|
Future income taxes
|
|
—
|
|
Future net cash flows
|
|
774,284
|
|
Discount of future net cash flows at 10% per annum
|
|
291,537
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
482,747
|
|
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
|
|
|
|
(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. 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, 2017 and 2016. As such, future development costs at December 31, 2017 and 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, 2017
,
2016
and
2015
used in the above table, were
$51.34
,
$42.75
and
$50.28
per Bbl of oil, respectively, and
$2.98
,
$2.48
and
$2.59
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, 2017:
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(99,260
|
)
|
Net changes in prices and production costs
|
|
91,998
|
|
Extensions and discoveries, net of future development and production costs
|
|
25,459
|
|
Development costs during the period to the extent previously estimated
|
|
1,913
|
|
Changes in estimated future development costs
|
|
(4,758
|
)
|
Revisions of previous quantity estimates
|
|
88,825
|
|
Sales of reserves in place
|
|
—
|
|
Purchase of reserves in place
|
|
40,991
|
|
Accretion of discount
|
|
31,093
|
|
Changes in timing and other
|
|
(4,444
|
)
|
Net change in income taxes
|
|
—
|
|
Net change
|
|
$
|
171,817
|
|
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 to the extent previously estimated
|
|
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 to the extent previously estimated
|
|
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
|
)
|
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
|
|
2017
|
|
2016
|
|
2015
|
|
2014 and
prior
|
Property acquisition costs
|
|
$
|
71,244
|
|
|
$
|
10,890
|
|
|
$
|
899
|
|
|
$
|
11,121
|
|
|
$
|
48,334
|
|
Exploration and development
|
|
10,820
|
|
|
10,820
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Capitalized interest
|
|
36,588
|
|
|
6,440
|
|
|
5,213
|
|
|
8,464
|
|
|
16,471
|
|
Total
|
|
$
|
118,652
|
|
|
$
|
28,150
|
|
|
$
|
6,112
|
|
|
$
|
19,585
|
|
|
$
|
64,805
|
|
Chapter 11 Cases
On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases are being jointly administered under the caption
In Re EXCO Resources, Inc., Case No. 18-30155 (MI)
. The Court has granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.
Impact on indebtedness
As of January 15, 2018, we had approximately
$1.4 billion
in principal amount of indebtedness, including approximately: (i)
$126.4 million
outstanding under the EXCO Resources Credit Agreement, (ii)
$317.0 million
in outstanding under the 1.5 Lien Notes, (iii)
$708.9 million
outstanding under the 1.75 Lien Term Loans, (iv)
$17.2 million
outstanding under the Second Lien Term Loans, (v)
$131.6 million
outstanding under the 2018 Notes and (vi)
$70.2 million
outstanding under the 2022 Notes. The commencement of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:
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EXCO Resources Credit Agreement;
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These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As a result of the bankruptcy proceedings, the Court may limit post-petition interest on debt that may be under secured or unsecured. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.
DIP Credit Agreement
On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax, Bluescape and JPMorgan Chase Bank, N.A. ("DIP Lenders"). Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The DIP Credit Agreement includes the Revolver A Facility in an aggregate principal amount of
$125.0 million
and the Revolver B Facility in an aggregate principal amount of
$125.0 million
.
All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus
4.00%
per annum. During the continuance of an event of default, the outstanding amounts under the DIP Facilities bear interest at an additional
2.00%
per annum above the interest rate otherwise applicable.
The DIP Facilities will mature on the earliest of (a)
12
months from the initial borrowings on January 22, 2018, (b) the effective date of a plan of reorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. We have the option, subject to certain conditions, to extend the maturity of the DIP Facilities to the date that is
18
months from the initial borrowing date. Borrowings under the DIP Credit Agreement are subject to a borrowing base based on the value of our oil and gas reserves. Beginning on January 1, 2019, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year. The initial borrowing base under the DIP Facilities is
$250.0 million
. The DIP Lenders have considerable discretion in setting our borrowing base as part of the redetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of the net present value, discounted at
nine
percent, of our Proved Developed Reserves.
The proceeds of the DIP Facilities may be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCO Resources Credit Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a budget provided to the DIP Lenders under the DIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses, and (iv) pay for certain other costs and expenses of administering the Chapter 11 Cases. We used approximately
$104.0 million
of the proceeds provided through the DIP Facilities to refinance all obligations outstanding under the EXCO Resources Credit Agreement (the “ERCA Refinancing”). Under the DIP Credit Agreement, approximately
$24.0 million
of outstanding letters of credit were deemed issued under the Revolver A Facility, and approximately
$21.6 million
of loans outstanding under the EXCO Resources Agreement were deemed exchanged for loans under the Revolver B Facility. On January 18, 2018, the Court entered an interim order (the “DIP Interim Order”) that authorized us to enter into the DIP Facilities. Under the Interim Order, the ERCA Refinancing was subject to a challenge and review period that expired on the date of the Court hearing on the final order (the “DIP Challenge Period”). On February 22, 2018, the Court entered into a final order authorizing entry into the DIP Credit Agreement on a final basis. The entry into the final order resulted in the expiration of the DIP Challenge Period and the termination of the EXCO Resources Credit Agreement. As of February 28, 2018, we had
$156.4 million
in outstanding indebtedness under the DIP Facilities, excluding letters of credit. Our available borrowing capacity under the DIP Facilities was
$69.6 million
as of February 28, 2018.
The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below) and the terms of the Interim Order, at all times: (i) are entitled to joint and several super-priority administrative expense claim status in the Chapter 11 cases; (ii) have a first priority lien on substantially all of our assets; (iii) have a junior lien on any of our assets subject to a valid, perfected and non-avoidable lien as of the Petition Date, other than such liens securing the obligations under the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of
100%
of the stock and other equity interests in each of our direct and indirect subsidiaries. Our obligations to the DIP Lenders and the liens and super-priority claims are subject in each case to a carve out (the “Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.
The DIP Credit Agreement contains certain financial covenants, including, but not limited to:
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our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than of
$20.0 million
; and
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aggregate disbursements cannot exceed
120%
of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the administrative agent of the DIP Credit Agreement.
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The DIP Facilities contain events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Facilities contained an event of default if we failed to pursue a Court hearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets. This requirement to pursue the court hearing to consider the sale of assets may have been waived by Fairfax, and the DIP Lenders and the Company were required negotiate in good faith the terms of a plan of reorganization to equitize certain indebtedness as an alternative to the sale process. On February 22, 2018, the final order entered by the Court deemed the requirement to pursue a Court hearing to consider the sale of all or substantially all of our assets to be no longer in force and effect.
The foregoing description does not purport to be a complete description of the DIP Credit Agreement, a copy of which is filed as an exhibit to the Current Report on Form 8-K, dated January 25, 2018.
Automatic stay
Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and the Filing Subsidiaries as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, for example, most creditor actions to obtain possession of property from us or any of the Filing Subsidiaries, or to create, perfect or enforce any lien against our property or any of the Filing Subsidiaries, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are stayed.
Executory contracts
Subject to certain exceptions, under the Bankruptcy Code, the Company and the Filing Subsidiaries may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the petition date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company and the Filing Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against us or the applicable Filing Subsidiaries for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Company and the Filing Subsidiaries to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Any description of the treatment of an executory contract or unexpired lease with the Company or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights we have with respect to executory contracts and unexpired leases under the Bankruptcy Code.
On January 18, 2018, the Company and the Filings Subsidiaries filed motions to reject certain executory contracts as permitted under the Bankruptcy Code. The contracts include the following:
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Firm transportation agreements with Acadian, which required us to transport
325,000
Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025;
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Natural gas sales agreements with Enterprise, which required us to sell
75,000
Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025;
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Firm transportation agreements with Regency, which required us to either transport
237,500
Mmbtu per day of natural gas or pay reservation charges through January 31, 2020;
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Marketing agreement with Chesapeake, which required us to allow Chesapeake to purchase natural gas for certain wells in North Louisiana through 2021; and
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Natural gas sales agreements with Shell, which required us to sell
100,000
Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020.
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On March 7, 2018, the Court approved the rejection of the aforementioned executory contracts with Regency, Chesapeake and Shell. The hearing to consider the motion to reject the Enterprise and Acadian contracts is scheduled for March 29, 2018. On March 1, 2018, the Company and the Filing Subsidiaries filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems through November 30, 2018. The hearing to consider this motion is scheduled for March 29, 2018. See further discussion of the future minimum obligations under these contracts as of December 31, 2017 in "Note 8. Commitments and contingencies".
Chapter 11 filing impact on creditors and shareholders
Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common shares are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors, if any, will not be determined until confirmation and implementation of a plan of reorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors may receive. We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 Cases, and the holders of our existing common shares will be entitled to a limited recovery, if any.
Restrictions on trading of our equity securities to protect our use of net operating losses
The Court has entered a final order pursuant to Sections 362(a)(3) and 541 of the Bankruptcy Code enabling the Company and the Filing Subsidiaries to avoid limitations on the use of our income tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least
4.5%
of our outstanding common stock (a “Substantial Stockholder”), and requires that each Substantial Stockholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Stockholder, or that would result in a person or entity becoming a Substantial Stockholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.
Risks associated with Chapter 11 proceedings
For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 proceedings as described in "Item 1A. Risk Factors”. As a result of these risks and uncertainties, our assets, liabilities, shareholders' equity, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.
Appalachia JV Settlement
On January 26, 2018, we filed a motion to authorize the entry into a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region. The final order related to this settlement was approved on February 22, 2018 and we closed the settlement agreement on
February 27, 2018
. Under the terms of the settlement:
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Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and the Appalachia Midstream JV;
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Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV;
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EXCO reconveyed its interests in certain leases, representing an interest in
364
net acres, that EXCO had previously acquired from Shell within the area of mutual interest, in exchange for consideration of
$0.7 million
;
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EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages and remedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest, the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region, except as expressly provided in the settlement; and
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EXCO caused the arbitration and the state court action to be dismissed with prejudice.
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The settlement increased our acreage in the Appalachia region by approximately
177,700
net acres, and the production from the additional interests in producing wells acquired was
26
net Mmcfe per day during December 2017. In addition, EXCO owns
100%
of OPCO and the Appalachia Midstream JV subsequent to the settlement.