Company Quick10K Filing
Quick10K
Exco Resources
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-01-18 Enter Agreement
8-K 2019-01-18 Enter Agreement
8-K 2018-11-28 Regulation FD, Exhibits
8-K 2018-02-22 Enter Agreement, Exhibits
8-K 2018-01-19 Enter Agreement, Off-BS Arrangement, Other Events, Exhibits
8-K 2018-01-15 Bankruptcy, Off-BS Arrangement, Regulation FD, Exhibits
KMI Kinder Morgan 44,840
PLNT Planet Fitness 6,840
VRNS Varonis Systems 1,860
KALU Kaiser Aluminum 1,700
NBR Nabors Industries 1,390
ASFI Asta Funding 31
CHEK Check-Cap 20
DBB Invesco DB Base Metals Fund 0
CFSC Caterpillar Financial Services 0
UCC Union Carbide 0
XCO 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for The Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions and Director Independence
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
EX-21.1 exhibit211subsidiarylist20.htm
EX-31.1 exhibit311peo2018.htm
EX-31.2 exhibit312pfo2018.htm
EX-32.1 exhibit321pfopeo2018.htm
EX-99.1 exhibit991nsai2018.htm
EX-99.2 exhibit992ryderscott2018.htm

Exco Resources Earnings 2018-12-31

XCO 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 xco2018123110k.htm 10-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018
OR
o
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE TRANSITION PERIOD FROM __________TO __________ 
Commission file number: 001-32743
EXCO RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
Texas
(State of incorporation)
 
74-1492779
(I.R.S. Employer Identification No.)
 
 
 
12377 Merit Drive, Suite 1700, Dallas, Texas
(Address of principal executive offices)
 
75251
(Zip Code)
Registrant’s telephone number, including area code: (214) 368-2084
Securities registered pursuant to Section 12 (b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act: Common Shares, par value $0.001 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer o
Non-accelerated filer þ
 
Smaller reporting company þ
Emerging growth company o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
As of March 8, 2019, the registrant had 21,584,514 outstanding common shares, par value $0.001 per share, which is its only class of common shares. As of the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common shares held by non-affiliates was approximately $1,501,809.
______________________________

DOCUMENTS INCORPORATED BY REFERENCE
The registrant intends to file an amendment on Form 10-K/A not later than 120 days after the close of the fiscal year ended December 31, 2018. Portions of such amendment will be incorporated by reference into Part III, Items 10-14 of this Annual Report on Form 10-K.




EXCO RESOURCES, INC.
TABLE OF CONTENTS
PART I.
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II.
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III.
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
Part IV.
 
 
Item 15.
Item 16.





EXCO RESOURCES, INC.
PART I

 
Item 1.    Business

General

Unless the context requires otherwise, references in this Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” “Company,” “we,” “our,” and “us” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of selected oil and natural gas terms” section of this Annual Report on Form 10-K.

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. Our primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and acquisition opportunities.

Bankruptcy proceedings under Chapter 11

On January 15, 2018 ("Petition Date"), the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP, 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.

DIP Credit Agreement

On January 22, 2018, we closed a debtor-in-possession credit agreement (“DIP Credit Agreement”) with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”). The DIP Credit Agreement includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). Proceeds from the DIP Facilities were used to repay all obligations outstanding under our previous revolving credit agreement ("EXCO Resources Credit Agreement") and will provide additional liquidity to fund our operations during the Chapter 11 Cases. On January 15, 2019, we entered into an amendment to the DIP Credit Agreement to extend the maturity date from January 22, 2019 to May 22, 2019. See further discussion of the DIP Credit Agreement in “Note 5. Debt” in the Notes to our Consolidated Financial Statements.

Impact on our indebtedness

The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the EXCO Resources Credit Agreement, senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), senior unsecured notes due September 15, 2018 (“2018 Notes”), and senior unsecured notes due April 15, 2022 (“2022 Notes”). These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code. On February 22, 2018, the Court approved our ability to make

1



adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. See further discussion of the impact in “Note 5. Debt” in the Notes to our Consolidated Financial Statements.

Rejection of executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Company or the applicable Filing Subsidiaries for damages caused by such rejection.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. On November 19, 2018, the Court approved an agreement to settle any claims related to a minimum volume commitment for gathering services in the East Texas and North Louisiana regions.

On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022. See further discussion of the impact of the rejection and settlement of executory contracts as part of “Note 1. Organization and basis of presentation” in the Notes to our Consolidated Financial Statements.

Status of plan of reorganization

On October 1, 2018, the Debtors filed a Settlement Joint Chapter 11 Plan of Reorganization (the “October 2018 Plan”) and related Disclosure Statement with the Court. As is customary in bankruptcy proceedings, the Debtors subsequently filed amendments to the October 2018 Plan and related Disclosure Statement with the Court. The distributions under the October 2018 Plan were expected to be funded with: (i) cash on hand; (ii) a new revolving credit facility; (iii) a new second lien debt instrument; (iv) the equity in the reorganized Company; and, (v) the D&O Proceeds, as defined below.

On November 5, 2018, the Court authorized us to solicit acceptances of the October 2018 Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the October 2018 Plan. Simultaneous with the solicitation process, we initiated a marketing process for the issuance of the new revolving credit facility and the new second lien debt instrument. During the course of the marketing process, oil prices experienced a significant decline and overall market conditions worsened. As a result, we were not able to obtain the exit financing required to consummate the October 2018 Plan. On February 15, 2019, the Court approved a motion to extend the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019.

On March 8, 2019, the Debtors filed a Second Amended Joint Chapter 11 Plan of Reorganization (“March 2019 Plan”) and related Disclosure Statement with the Court. The March 2019 Plan provides for either a reorganization of the Debtors as a going concern or the sale of the Debtors’ assets (“All Asset Sale”). The Debtors will make a final determination regarding which path to pursue by the date of the hearing to approve the Disclosure Statement. The March 2019 Plan included the following key elements:

Holders of the DIP Credit Agreement will receive payment in full in cash with proceeds from either a new revolving credit facility (“Exit Facility”) or, in the event of an All Asset Sale, proceeds from the sale of assets;
Holders of allowed 1.5 Lien Notes claims will receive either their pro rata share of a new mandatorily convertible security or, in the event of an All Asset Sale, the liens securing such allowed claim;
Holders of allowed 1.75 Lien Term Loans claims will receive either their pro rata share of the equity in the reorganized Company representing the value attributable to encumbered assets or, in the event of an All Asset Sale, the liens securing such allowed claim;
Holders of the Second Lien Term Loans, 2018 Notes, 2022 Notes, allowed general unsecured claims and deficiency claims associated with the 1.75 Lien Term Loans will receive either their pro rata share of equity in the reorganized Company representing the value attributable to unencumbered assets, or in the event of an All Asset Sale, proceeds attributable to the sale of the unencumbered assets (“Unsecured Claims Recovery”);
Holders of existing equity interests in EXCO shall not receive a distribution and the equity interests will be deemed canceled, discharged, released and extinguished; and
The carriers of directors’ and officers’ liability insurance coverage related to the Debtors will contribute $13.4 million (“D&O Proceeds”) to the Debtors in exchange for full and final settlement of potential claims and causes of action against current and former directors and officers.

2




The March 2019 Plan does not release the Debtors or holders of claims of the 1.5 Lien Notes and 1.75 Lien Term Loans from certain causes of action. The litigation of these causes of action will be managed by a trustee appointed by the committee of unsecured creditors of the Debtors and will not occur until after the confirmation of the March 2019 Plan. If any of the disputed claims are successfully prosecuted, this could materially impact the aforementioned recoveries for holders of allowed claims. If some or all of the 1.5 Lien Notes claims or 1.75 Lien Term Loans claims are deemed to be unsecured claims following the successful prosecution of a secured claims challenge, the holders of such 1.5 Lien Notes claims and 1.75 Lien Term Loans claims will receive their pro rata share of the Unsecured Claims Recovery. We have not received consents from any creditors in support of the March 2019 Plan. Therefore, our ability to confirm the March 2019 Plan is subject to a high degree of uncertainty.

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 Cases in "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements.

Summary of geographic areas of operations

The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2018:
Areas
 
Total Proved Reserves (Bcfe) (1)
 
PV-10 (in millions) (1) (2)
 
Average daily net production (Mmcfe/d) (3)
North Louisiana
 
285.5

 
$
280.0

 
163

East Texas
 
59.4

 
58.0

 
24

South Texas
 
90.1

 
304.9

 
28

Appalachia and other
 
225.6

 
114.5

 
51

Total
 
660.6

 
$
757.4

 
266


Areas
 
Total gross acreage
 
Total net acreage
North Louisiana
 
101,400

 
55,500

East Texas
 
110,000

 
41,100

South Texas
 
100,800

 
48,500

Appalachia and other
 
382,200

 
342,800

Total
 
694,400

 
487,900


(1)
The total Proved Reserves and PV-10 as of December 31, 2018 were prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC").
(2)
The PV-10 data used in this table was based on reference prices using the simple average of the spot prices for the trailing 12 month period using the first day of each month beginning on January 1, 2018 and ending on December 1, 2018, of $3.10 per Mmbtu for natural gas and $65.56 per Bbl for oil, in each case adjusted for geographical and historical differentials. Market prices for oil and natural gas are volatile (see “Item 1A. Risk Factors - Risks Relating to Our Business”). We believe that PV-10, while not a financial measure in accordance with generally accepted accounting principles in the United States ("GAAP"), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics which can differ significantly among comparable companies. The total Standardized Measure, a measure recognized under GAAP, as of December 31, 2018 was $757.4 million. The Standardized Measure represents the PV-10 after giving effect to income taxes and is calculated in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 932, Extractive Activities, Oil and Gas ("ASC 932"). Our tax basis in the associated properties exceeded the pre-tax cash inflows and, as a result, there is no difference in Standardized Measure and PV-10 for all years presented. The amount of estimated future plugging and abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us.
(3)
The average daily net production rate was calculated based on the average daily rate during the final month of the year ended December 31, 2018.


3



Our development and exploitation project areas
excomap2016a01.jpg
East Texas and North Louisiana

Our operations in East Texas and North Louisiana are focused on the Haynesville and Bossier shales, which are primarily located in Shelby, Harrison, Panola, San Augustine and Nacogdoches Counties in Texas and DeSoto and Caddo Parishes in Louisiana. Our acreage in this region is predominantly held-by-production. The Haynesville shale is located at depths of 12,000 to 14,500 feet and is being developed with horizontal wells that typically have 4,500 to 10,000 foot laterals. The lateral lengths of future wells to be drilled in this region are dependent on factors including our acreage position and nearby existing wells. The Bossier shale lies above certain portions of the Haynesville shale and also contains rich deposits of natural gas. The geographic position of our properties in the Haynesville and Bossier shales provides us access to nearby markets with favorable natural gas price indices compared to the rest of the country.

North Louisiana

Our position in the Holly area of North Louisiana consists of 30,800 net acres in DeSoto Parish and 11,700 net acres in Caddo Parish, which are predominantly held-by-production. At December 31, 2018, we had a total of 434 gross (236.5 net) operated wells flowing to sales. Our development activities in North Louisiana during 2018 primarily focused on the completion of 13 gross (7.4 net) operated wells drilled in prior year and drilling of 6 gross (3.6 net) operated wells. Including non-operated volumes, our average natural gas production was approximately 163 net Mmcfe per day during December 2018. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. During November 2018, the Court approved an agreement to settle any claims related to a minimum volume commitment for the gathering of natural gas production in the East Texas and North Louisiana regions. The rejection and settlement of these agreements resulted in a significant improvement in our realized natural gas price differentials, gathering expenses, and transportation expenses. We plan to drill 1 gross (0.6 net) operated well in the Haynesville shale during the first quarter of 2019 and complete 11 gross (6.2 net) operated wells in the Haynesville shale during the first three quarters of 2019. In addition, we plan to perform refracs on 3 gross (1.5 net) wells utilizing an improved design that includes a cemented liner and increased proppant volumes.


4



East Texas

Our operations in East Texas are focused on the Haynesville and Bossier shales. Our acreage is primarily located in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas and is predominantly held-by-production. The Haynesville and Bossier shales in East Texas are being developed with horizontal wells that typically have 6,000 to 7,500 foot laterals. Our position in the Shelby area of East Texas primarily consists of 30,400 net acres and includes approximately 9,700 net acres subject to continuous drilling obligations. We plan to drill, or participate with another operator in drilling, on the acreage subject to the continuous drilling obligation in the future to hold the acreage. Excluding the acreage subject to the continuous drilling obligation, approximately 96% of our net acres are held-by-production in the Shelby area.

As of December 31, 2018, we had a total of 102 gross (45.9 net) operated wells flowing to sales. Our development in this region during 2018 was limited to the participation in certain non-operated wells. Including non-operated volumes, our average natural gas production was approximately 24 net Mmcfe per day during December 2018. Our plans for 2019 include the participation in non-operated wells that will satisfy our continuous drilling obligation in the southern portion of the region. In addition, we plan to participate in certain non-operated wells to appraise our position in Harrison and Panola Counties. Our position in Harrison and Panola Counties consists of 5,400 net acres.

South Texas

Our position in this region includes approximately 48,500 net acres, of which approximately 95% are held-by-production. Our South Texas acreage covers portions of Zavala, Dimmit and Frio Counties. Our acreage in the Eagle Ford shale is in the oil window and averages 375 feet in gross thickness at true vertical depths ranging from 5,400 to 6,800 feet. Our lateral lengths range from 5,000 to 10,000 feet and the total measured depth averages 14,600 feet. Our acreage in the area also includes additional upside in formations such as the Austin Chalk, Buda, Georgetown and Pearsall formations.

As of December 31, 2018, we had a total of 236 gross (107.9 net) operated horizontal wells flowing to sales. Including non-operated volumes, our average oil production in South Texas was approximately 4,700 net barrels of oil equivalent per day during December 2018. Our ability to transport or sell the natural gas from this region has been limited since the alleged termination of a long-term natural gas sales contract by the primary purchaser of our natural gas in May 2017. As a result, we commenced flaring natural gas in January 2018. We are evaluating operational and commercial solutions for the natural gas production in order to avoid significant curtailments of our oil production. See further discussion of the risks related to our ability to sell or transport natural gas from this region in "Item 1A. Risk Factors". Our development program during 2018 focused on the Eagle Ford shale, which included drilling 14 gross (11.3 net) operated wells and completing 16 gross (12.9 net) operated wells. We plan to drill 26 gross (8.5 net) and turn-to-sales 23 gross (7.4 net) operated wells in the Eagle Ford shale during 2019. In addition, our plans for 2019 include the construction of an electrical distribution network over the core development area that will provide a more efficient cost structure to operate the field.

Appalachia
    
Our operations in the Appalachia region have primarily included testing and selectively developing the Marcellus shale with horizontal drilling. As of December 31, 2018, we held approximately 339,800 net acres in the Appalachia region, including approximately 234,800 net acres prospective for the Marcellus shale and approximately 69,000 net acres prospective for the dry gas window of the Utica shale in Pennsylvania. 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. 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. See further discussion of this settlement as part of "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements. Drilling, completion and production activities in Pennsylvania target the Marcellus shale as well as deeper formations including the Utica shale at depths ranging from 5,000 to more than 12,000 feet. Approximately 98% of our acreage is held-by-production, which allows us to control the timing of the development of this region.

As of December 31, 2018, we operated a total of 116 gross (83.3 net) horizontal wells in the Marcellus shale. During 2018, we turned-to-sales 1 gross (0.9 net) operated Marcellus shale well in Northeast Pennsylvania that was previously awaiting the connection of a pipeline. Including non-operated volumes, our production in the Appalachia region was approximately 51 net Mmcfe per day during December 2018. In recent years, we have limited our development of the Marcellus shale due to wide regional natural gas price differentials. These differentials continue to be volatile; however, the differentials in the region narrowed during 2018 and have the potential to be favorably impacted by the expansion of infrastructure and other sources of demand for natural gas in the Northeast region in future years. We have an extensive inventory of undeveloped locations prospective for the Marcellus and Utica shales that has potential to provide attractive rates

5



of return through enhanced completion designs and an improved commodity price environment. Our plans for 2019 include drilling and turning-to-sales 2 gross (1.9 net) operated Marcellus shale wells in Northeast Pennsylvania. These wells will feature an enhanced completion design that includes increased proppant volumes and tighter cluster spacing, which has proven to be effective on recent wells in the region. We do not have any producing wells in the dry gas window of the Utica shale; however, we are currently assessing the potential of the formation to determine the extent of future development. Our plans for 2019 include drilling and turning-to-sales 1 gross (1.0 net) operated appraisal well targeting the dry gas window of the Utica shale in Central Pennsylvania.

Our hydraulic fracturing activities

Oil and natural gas may be recovered from our properties through the use of sophisticated drilling and hydraulic fracturing techniques. Hydraulic fracturing involves the injection of water, sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Our hydraulic fracturing activities are primarily focused in the Eagle Ford shale in South Texas, Haynesville and Bossier shales in East Texas and North Louisiana and Marcellus shale in the Appalachia region. Predominantly all of our Proved Reserves are associated with shale assets in these areas.

Although the cost of each well will vary, the costs associated with the hydraulic fracturing portion of the well on average represent the following percentages of the total costs of drilling and completing a well: 40-50% in the Haynesville and Bossier shale formation; 45-55% in the Eagle Ford shale formation; and 35-45% in the Marcellus shale formation. These costs may increase in future periods as a result of higher levels of proppant utilized in the completion of our shale wells.

We review best practices and industry standards to comply with regulatory requirements in the protection of potable water sources when drilling and completing our wells. Protective practices include, but are not limited to, setting multiple strings of protection pipe across potable water sources and cementing these pipe strings to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of non-recycled produced fluids in authorized disposal wells at depths below the potable water sources. In addition, we actively seek methods to minimize the environmental impact of our hydraulic fracturing operations in all of our operating areas.

For more information on the risks of hydraulic fracturing, see “Item 1A. Risk Factors - Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures” and “Item 1A. Risk Factors - Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays".

Marketing arrangements

We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the oil we produce under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend up to a year. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions.

We may be unable to market all of the oil or natural gas we produce. If our oil and natural gas cannot be marketed, we may be unable to negotiate favorable pricing and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.
We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. If this occurs, companies purchasing oil or natural gas in these areas may reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our oil or natural gas reserves, we may shut-in our oil or natural gas wells for certain periods of time. Furthermore, we may shut-in our oil and natural gas wells if regional market prices decrease to a level that is uneconomical to produce. If

6



this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Economic conditions, particularly depressed oil and natural gas prices, may negatively impact the liquidity and creditworthiness of our purchasers and may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

Raider Marketing, LP ("Raider") is a wholly owned subsidiary of EXCO and is the contractual counterparty by operation of Texas law to all of EXCO's gathering, transportation and marketing contracts in Texas and Louisiana. Raider purchases and resells natural gas from third-party producers as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells.

The availability of a ready market and the prices for oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:

supply and demand for oil and natural gas and expectations regarding supply and demand;
the level of domestic and international production;
the availability of imported oil and natural gas;
federal regulations applicable to the export of, and construction of export facilities for, oil and natural gas;
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, sanctions, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
domestic and international government regulation, legislation and policies, including levying tariffs on oil and natural gas imports;
the cost and availability of transportation and pipeline systems with adequate capacity;
the cost and availability of other competitive fuels;
fluctuating and seasonal demand for oil, natural gas and refined products;
concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;
regional price differentials and quality differentials of oil and natural gas;
the availability of refining capacity;
technological advances affecting oil and natural gas production and consumption;
weather conditions and natural disasters;
foreign and domestic government relations; and
overall domestic and global economic conditions.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.


7



Our oil and natural gas reserves

Our Proved Reserves as of December 31, 2018 were approximately 660.6 Bcfe, of which approximately 52% were located in the Haynesville/Bossier shales, 34% in the Marcellus shale and 14% in the Eagle Ford shale.

The following table summarizes our Proved Reserves as of December 31, 2018, 2017 and 2016. This information was prepared in accordance with the rules and regulations of the SEC. The comparability of our reserves is impacted by commodity prices, purchases and sales of reserves in place, production, revisions of previous estimates, changes in our development plans, and discoveries and extensions. See "Management's discussion and analysis of oil and natural gas reserves" for a summary of the changes in our Proved Reserves.
 
 
As of December 31,
 
 
2018 (3)
 
2017 (3)
 
2016 (3)
Oil (Mbbls)
 
 
 
 
 
 
Developed
 
13,302

 
9,412

 
10,168

Undeveloped
 

 

 

Total
 
13,302

 
9,412

 
10,168

 
 
 
 
 
 
 
Natural gas (Mmcf)
 
 
 
 
 
 
Developed
 
580,781

 
510,451

 
415,719

Undeveloped
 

 

 

Total
 
580,781

 
510,451

 
415,719

 
 
 
 
 
 
 
Equivalent reserves (Mmcfe)
 
 
 
 
 
 
Developed
 
660,590

 
566,924

 
476,727

Undeveloped
 

 

 

Total
 
660,590

 
566,924

 
476,727

 
 
 
 
 
 
 
PV-10 (in millions) (1)
 
 
 
 
 
 
Developed
 
$
757.4

 
$
482.7

 
$
310.9

Undeveloped
 

 

 

Total
 
$
757.4

 
$
482.7

 
$
310.9

 
 
 
 
 
 
 
Standardized Measure (in millions) (2)
 
$
757.4

 
$
482.7

 
$
310.9


(1)
The PV-10 is based on the following average spot prices, in each case adjusted for historical differentials. Prices presented on the table below are the trailing 12 month simple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma.
 
 
Average spot prices
 
 
Oil (per Bbl)
 
Natural gas (per Mmbtu)
December 31, 2018
 
$
65.56

 
$
3.10

December 31, 2017
 
51.34

 
2.98

December 31, 2016
 
42.75

 
2.48

(2)
There is no difference in Standardized Measure and PV-10 for all years presented as our tax basis in the associated properties exceeded the pre-tax cash inflows. We believe that PV-10, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics, which can differ significantly among comparable companies. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with ASC 932.
(3)
All of our undeveloped locations that meet the technical definition of Proved Undeveloped Reserves based on engineering guidelines remain classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, because the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2018, 2017 and 2016. 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.

8




Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls include documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. Our internal processes and controls surrounding this process are routinely tested. We also retain outside independent engineering firms to prepare estimates of our Proved Reserves. Senior management reviews and approves our reserve estimates, whether prepared internally or by third parties. Our Chief Operating Officer oversaw our outside independent engineering firms, Netherland, Sewell & Associates, Inc. ("NSAI"), and Ryder Scott Company, L.P. ("Ryder Scott") in connection with the preparation of their estimates of our Proved Reserves as of December 31, 2018. We also regularly communicate with our outside independent engineering firms throughout the year regarding technical and operational matters critical to our reserve estimations. Our Chief Operating Officer, with input from other members of senior management, is responsible for the selection of our third-party engineering firms and review of the reports generated by such firms. Our Chief Operating Officer has over 27 years of experience in the oil and natural gas industry and is a graduate of Texas Tech University with a degree in Petroleum Engineering. During his career, he has had multiple responsibilities in technical or leadership roles including asset management, drilling and completions, production engineering, reservoir engineering and reserves management, economic evaluations and field development in U.S. onshore and international projects. The third-party engineering reports are also provided to the Audit Committee.

Our estimated Proved Reserves and future net cash flows for our shale properties in all regions except South Texas were prepared by NSAI as of December 31, 2018 and 2017. Our estimated Proved Reserves and future net cash flows for our shale properties in the South Texas region were prepared by Ryder Scott as of December 31, 2018 and 2017. Differences may exist between reserve quantities and values as presented in this Form 10-K and the reports of third party engineering firms filed herewith due to the exclusion of certain properties from the reports of third party engineering firms and immaterial differences in the calculations performed by the reserves evaluation software utilized by management and the third party engineering firms for estimating reserves and values.

NSAI and Ryder Scott are independent petroleum engineering firms that perform a variety of reserve engineering and valuation assessments for public and private companies, financial institutions and institutional investors. NSAI and Ryder Scott have performed these services for over 50 years. Our internal technical employees responsible for reserve estimates and interaction with our independent engineers include employees and corporate officers with petroleum and other engineering degrees and relevant industry experience.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm's communication with EXCO's engineers and geologists, the collection of any and all required geological, geophysical, engineering and economic data, and such firm's complete external preparation of all required estimates and are forward-looking in nature. These reports rely on various assumptions, including definitions and economic assumptions required by the SEC, including the use of constant oil and natural gas pricing, use of current and constant operating costs and capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our Proved Undeveloped Reserves. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the Proved Reserves will ultimately be realized. Our actual results could differ materially. See “Note 16. Supplemental information relating to oil and natural gas producing activities (unaudited)” in the Notes to our Consolidated Financial Statements for additional information regarding our oil and natural gas reserves and the Standardized Measure.

NSAI and Ryder Scott also examined our estimates with respect to reserve categorization, using the definitions for Proved Reserves set forth in SEC Regulation S-X Rule 4-10(a) and SEC staff interpretations and guidance. In preparing an estimate of our Proved Reserves and future net cash flows attributable to our interests, NSAI and Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of the examination anything came to the attention of NSAI or Ryder Scott, which brought into question the validity or sufficiency of any such information or data, NSAI or Ryder Scott did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. NSAI and Ryder Scott determined that their estimates of Proved Reserves conform to the guidelines of the SEC, including the criteria of Reasonable Certainty, as it pertains to expectations about the recoverability of Proved Reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.


9



Management's discussion and analysis of oil and natural gas reserves

The following discussion and analysis of our proved oil and natural gas reserves and changes in our Proved Reserves is intended to provide additional guidance on the operational activities, transactions, economic and other factors which significantly impacted our estimate of Proved Reserves as of December 31, 2018 and changes in our Proved Reserves during 2018. This discussion and analysis should be read in conjunction with “Note 16. Supplemental information relating to oil and natural gas producing activities (unaudited)” in the Notes to our Consolidated Financial Statements, and in “Item 1A. Risk Factors” addressing the uncertainties inherent in the estimation of oil and natural gas reserves elsewhere in this Annual Report on Form 10-K. The following table summarizes the changes in our Proved Reserves from January 1, 2018 to December 31, 2018.
 
 
Oil (Mbbls)
 
Natural gas (Mmcf)
 
Equivalent natural gas (Mmcfe)
Proved Developed Reserves
 
13,302

 
580,781

 
660,590

Proved Undeveloped Reserves
 

 

 

Total Proved Reserves
 
13,302

 
580,781

 
660,590

The changes in reserves for the year are as follows:
 
 
 
 
 
 
January 1, 2018
 
9,412

 
510,451

 
566,924

Purchases of reserves in place
 

 
118,415

 
118,415

Discoveries and extensions
 
1,387

 
22,482

 
30,804

Revisions of previous estimates:
 
 
 
 
 
 
Changes in price
 
690

 
5,726

 
9,866

Performance and other factors
 
3,170

 
22,486

 
41,502

Sales of reserves in place
 

 

 

Production
 
(1,357
)
 
(98,779
)
 
(106,921
)
December 31, 2018
 
13,302

 
580,781

 
660,590


Purchases of reserves in place

The 118.4 Bcfe of purchases of reserves in place for natural gas related to our acquisition of incremental interests in the Appalachia JV Settlement on February 27, 2018. The Proved Reserves acquired in the Appalachia JV Settlement predominantly consists of proved producing properties in the Marcellus shale.

Discoveries and extensions

Proved Reserve additions from discoveries and extensions were 30.8 Bcfe for the year ended December 31, 2018, primarily due to the development of operated wells in the Eagle Ford shale and non-operated wells in the Haynesville shale.

Revisions of previous estimates

Our revisions of previous estimates included upward revisions to our Proved Reserve quantities of 51.4 Bcfe. The increase in commodity prices contributed to 9.9 Bcfe of the upward revisions, which extended the economic life of certain producing properties when using prices prescribed by the SEC. This change in price was primarily driven by the increase in the trailing 12 month average of oil and natural gas prices. The trailing 12 month average oil price increased from $51.34 per Bbl for the year ended December 31, 2017 to $65.56 per Bbl for the year ended December 31, 2018 and the trailing 12 month average natural gas price increased from $2.98 per Mmbtu for the year ended December 31, 2017 to $3.10 per Mmbtu for the year ended December 31, 2018.

In addition, our revisions of previous estimates included 41.5 Bcfe due to performance and other factors. The revisions were primarily due to the reclassification of wells to Proved Reserves during 2018 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana and South Texas regions.

10



Oil and natural gas production

Total oil and natural gas production in 2018 was 106.9 Bcfe, which included approximately 2.8 Bcfe in production from extensions and discoveries that were not reflected in our Proved Reserves at January 1, 2018.

Proved Undeveloped Reserves

All of our undeveloped locations that meet the technical definition of Proved Undeveloped Reserves based on engineering guidelines are classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, because the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2018. During 2018, we converted certain unproved reserves to Proved Developed Reserves as a result of our drilling and completion activities. However, we did not report any changes in our Proved Undeveloped Reserves for the year ended December 31, 2018. 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.

Impacts of changes in reserves on depletion rate and statements of operations in 2018

Our depletion rate increased to $0.74 per Mcfe in 2018 from $0.57 per Mcfe in 2017. The increase was primarily due to the additional costs associated with our development of the South Texas and North Louisiana regions. In particular, the development of oil producing assets in South Texas results in a higher depletion rate when calculated on per Mcfe basis compared to the rest of our properties.

Our production, prices and expenses

The following table summarizes revenues, net production, average sales price per unit and costs and expenses associated with the production of oil and natural gas.
 
 
Year Ended December 31,
(in thousands, except production and per unit amounts)
 
2018
 
2017
 
2016
Revenues, production and prices:
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
Revenue
 
$
90,614

 
$
57,693

 
$
67,317

Production sold (Mbbls)
 
1,357

 
1,158

 
1,769

Average sales price per Bbl
 
$
66.78

 
$
49.82

 
$
38.05

Natural gas:
 
 
 
 
 
 
Revenue
 
$
281,977

 
$
201,137

 
$
181,332

Production sold (Mmcf)
 
98,779

 
80,136

 
93,829

Average sales price per Mcf
 
$
2.85

 
$
2.51

 
$
1.93

Costs and expenses:
 
 
 
 
 
 
Oil and natural gas operating costs per Mcfe
 
$
0.39

 
$
0.40

 
$
0.33



11



We had two areas that exceeded 15% of our total Proved Reserves as of December 31, 2018. The Holly field in North Louisiana and the Marcellus shale in Appalachia represented approximately 43% and 34% of our total Proved Reserves, respectively. The following table provides additional information related to our Holly and Marcellus shale areas:
 
Year Ended December 31,
 
2018

2017

2016
Holly area:
 
 
 
 
 
Natural gas production sold (Mmcf)
70,104

 
53,368

 
55,290

Average price per Mcf
$
2.94

 
$
2.60

 
$
2.00

Oil and natural gas operating costs per Mcf
0.29

 
0.32

 
0.23

Marcellus shale:
 
 
 
 
 
Natural gas production sold (Mmcf)
17,829

 
9,863

 
10,851

Average price per Mcf
$
2.51

 
$
2.14

 
$
1.50

Oil and natural gas operating costs per Mcf
0.24

 
0.17

 
0.12


Our interest in productive wells

The following table quantifies information regarding productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refer to the total number of physical wells in which we hold a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interests we hold in all wells. We compute the number of net wells by totaling the percentage interests we hold in all our gross wells.
 
 
At December 31, 2018
 
 
Gross wells (1)
 
Net wells
 
 
Oil
 
Natural gas
 
Total
 
Oil
 
Natural gas
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 

 
677

 
677

 

 
251.2

 
251.2

East Texas
 

 
157

 
157

 

 
50.3

 
50.3

South Texas
 
255

 
1

 
256

 
111.3

 
0.1

 
111.4

Appalachia and other
 
1

 
156

 
157

 

 
85.5

 
85.5

Total
 
256

 
991

 
1,247

 
111.3

 
387.1

 
498.4


(1)
As of December 31, 2018, we did not hold interests in any wells with multiple completions.

As of December 31, 2018, we operated 888 gross (473.6 net) wells, which represented approximately 90% of our Proved Developed Reserves.


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Our drilling activities

Our drilling activities are primarily focused on horizontal drilling in shale plays, particularly in the Haynesville, Bossier, Eagle Ford and Marcellus shales. The following tables summarize our approximate gross and net interests in the operated wells we drilled during the periods indicated and refer to the number of wells completed during the period, regardless of when drilling was initiated.
 
 
Development wells
 
 
Gross
 
Net
 
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
Year ended December 31, 2018 (1)
 
30

 

 
30

 
21.2

 

 
21.2

Year ended December 31, 2017 (2)
 
10

 

 
10

 
6.8

 

 
6.8

Year ended December 31, 2016 (3)
 
15

 

 
15

 
9.2

 

 
9.2

 
 
Exploratory wells
 
 
Gross
 
Net
 
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
Year ended December 31, 2018 (1)
 

 

 

 

 

 

Year ended December 31, 2017 (2)
 
2

 

 
2

 
1.6

 

 
1.6

Year ended December 31, 2016 (3)
 

 

 

 

 

 


(1)
Our development wells in 2018 primarily included the Haynesville shale in the Holly area of North Louisiana and the Eagle Ford shale of South Texas. None of the wells completed during the period were classified as exploratory.
(2)
Our development wells in 2017 primarily included the Haynesville shale in the Holly area of North Louisiana. Our exploratory wells included the Bossier shale in the Holly area of North Louisiana.
(3)
Our development in 2016 primarily included the Haynesville and Bossier shales in the Shelby area of East Texas and the Haynesville shale in the Holly area of North Louisiana. None of the wells completed during the period were classified as exploratory.

Our developed and undeveloped acreage

Developed acreage includes those acres spaced or assignable to producing wells or wells capable of producing. Undeveloped acreage represents those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. The following table sets forth our developed and undeveloped acreage:
 
 
At December 31, 2018
 
 
Developed
 
Undeveloped
Area
 
Gross
 
Net
 
Gross
 
Net
North Louisiana
 
77,700

 
37,700

 
23,700

 
17,800

East Texas
 
46,900

 
20,500

 
63,100

 
20,600

South Texas
 
94,300

 
45,400

 
6,500

 
3,100

Appalachia and other
 
53,300

 
38,100

 
328,900

 
304,700

Total
 
272,200

 
141,700

 
422,200

 
346,200


The primary terms of our oil and natural gas leases expire at various dates. Most of our undeveloped acreage is held-by-production, which means that these leases are active as long as there is production of oil or natural gas from wells on the acreage or certain lease terms are met. Upon ceasing production, these leases will expire. As of December 31, 2018, we had approximately 2,800; 5,900; and 200 net acres with lease expirations in 2019, 2020 and 2021, respectively. In addition, we have approximately 9,700 net acres located in the Shelby area of East Texas that are subject to continuous drilling obligations, and we plan to hold the acreage through drilling wells or participating in the drilling of non-operated wells on the acreage. Predominantly all of our expiring acreage is located within our shale resource plays.

The held-by-production acreage in many cases represents potential additional drilling opportunities through down-spacing and drilling of proved undeveloped and unproved locations in the same formation(s) already producing, as well as

13



other non-producing formations, in a given oil or natural gas field without the necessity of purchasing additional leases or producing properties.

Competition

The oil and natural gas industry is highly competitive, particularly with respect to acquiring prospective oil and natural gas properties and oil and natural gas reserves. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have substantially greater financial, managerial, technological and other resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas, but also have refining operations, market refined products and their own drilling rigs and oilfield services.
 

The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases and operational delays. We may experience difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict when, or if, supply or demand imbalances may occur or how these market-driven factors impact prices, which affect our development and exploitation programs. Furthermore, our relationships with vendors may be negatively impacted by the Chapter 11 Cases, including their perception of our financial condition and long-term business plans. This could further disadvantage our ability to obtain services or negatively impact the prices to obtain certain services.

The oil and gas industry continues to experience strong demand for drilling and completion services. The domestic U.S. onshore rig count increased from 374 in May 2016 to 1,056 in December 2018. Furthermore, oil and gas companies have increased the average amount of proppant utilized in the hydraulic fracturing process to enhance recoveries from the wells. As a result, the increased demand for drilling rigs and completion services could result in increased costs to develop our oil and gas properties.

Competition also exists for hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, tax and land professions. In addition, the market for oil and natural gas properties is competitive. We are often outbid by competitors in our attempts to lease or acquire properties. The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and renewable energy sources such as wind and solar power. Competitive conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. All of these challenges could make it more difficult to execute our growth strategy or result in an increase in our costs.

Applicable laws and regulations

General

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Laws, orders and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and financial sanctions for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, we believe these burdens do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

The following is a summary of the more significant existing environmental, safety and other laws and regulations to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

Production regulation

Our operations are subject to a number of regulations at the federal, state and local levels. These regulations require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. Many states, counties and municipalities in which we operate also regulate one or more of the following:

the location of wells;
the method of drilling, completing and operating wells;

14



the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells;
notice to surface owners and other third parties; and
produced water and waste disposal.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are also subject to well spacing, density and proration requirements of the Texas Railroad Commission that could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Some states, including Louisiana and Texas, allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, most states generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. Many local authorities also impose an ad valorem tax on the minerals in place. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

Our operations are subject to numerous stringent federal and state statutes and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties, as well as potential injunctive relief, for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transportation of oil and natural gas, govern the sourcing, storage and disposal of water used or produced in the drilling and completion process, restrict or prohibit drilling activities in certain areas and on certain lands lying within wetlands and other protected areas, require closing earthen impoundments and impose liabilities for pollution resulting from operations or failure to comply with regulatory filings.

Statutes, rules and regulations that apply to the exploration and production of oil and natural gas are often reviewed, amended, expanded and reinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statutes difficult. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, adversely affects its (and our) profitability.

FERC and CFTC matters

The availability, terms and cost of downstream transportation significantly affect sales of natural gas and oil. The interstate transportation of natural gas, including regulation of the terms, conditions and rates for interstate transportation and storage of natural gas, is subject to federal regulation by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Transportation rates under the NGA must be just and reasonable. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by requiring that interstate natural gas transportation be made available on an open-access, not unduly discriminatory basis. FERC’s jurisdiction under the NGA excludes gathering and distribution of natural gas; therefore, gathering and distribution of natural gas are subject to regulation by individual state laws. State regulations also govern the rates and terms for access to, and transportation of natural gas on, intrastate pipeline facilities (while intrastate pipelines may from time to time provide specific services that are subject to limited regulation by FERC). The interstate transportation of oil, including regulation of the rates, terms and conditions of service, is subject to federal regulation by FERC under the Interstate Commerce Act. Rates for such oil transportation must be just and reasonable and not unduly discriminatory. Oil transportation that is not federally regulated is left to state regulation.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the greenhouse gas (“GHG”) emissions of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.

The federal government recently ended its decades-old prohibition of exports of crude oil produced in the lower 48 states of the U.S. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of

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oil. The general perception in the industry is that ending the prohibition on exports of oil produced in the U.S. may have a positive impact on U.S. producers. In addition, the U.S. Department of Energy (“DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which is regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG export facilities being developed and constructed in the U.S. Gulf Coast region. While the volume of natural gas exports increased in 2018 and 2017, it is too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U.S. natural gas.

Wholesale prices for natural gas and oil are not currently regulated and are determined by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of natural gas market participants other than intrastate pipelines. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor markets and enforce anti-market manipulation regulations with respect to the physical and financial (futures, options and swaps) energy commodities market pursuant to the Commodity Exchange Act, as amended by the Dodd Frank Wall Street Reform and Consumer Protection Act of 2010. With regard to our physical sales of natural gas and oil, our gathering of any of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Federal, state or tribal oil and natural gas leases

In the event we conduct operations on federal, state or tribal oil and natural gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM"), Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement or other appropriate federal, state or tribal agencies.

Surface Damage Acts

In addition, a number of states and some tribal nations have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

Other regulatory matters relating to our pipeline and gathering system assets and rail transportation

The pipelines we use to gather and transport our oil and natural gas in interstate commerce are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”) with respect to oil, and the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and hazardous liquids pipeline facilities, including pipelines transporting crude oil. Where applicable, the HLPSA and NGPSA also require us and other pipeline operators to comply with regulations issued pursuant to these acts that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.

 The Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”) mandates requirements in the way that the energy industry ensures the safety and integrity of its pipelines. The law applies to natural gas and hazardous liquids pipelines, including some gathering pipelines. Central to the law are the requirements it places on each pipeline operator

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to prepare and implement an “integrity management program.” The Pipeline Safety Act mandates a number of other requirements, including increased penalties for violations of safety standards and qualification programs for employees who perform sensitive tasks. The DOT has established a number of rules carrying out the provisions of this act. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We could incur significant expenses as a result of these laws and regulations.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT under the NGPSA, the Pipeline Safety Act, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in January 2012. This law includes a number of provisions affecting pipeline owners and operators that became effective upon approval, including increased civil penalties for violators of pipeline regulations and additional reporting requirements. Most of the changes do not impact gathering lines. This legislation requires the PHMSA to issue or revise certain regulations and to conduct various reviews, studies and evaluations. In addition, the PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and for operators to establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisions to gathering line regulations and liquid pipelines regulations are enacted by PHMSA, we could incur significant expenses.

U.S. federal taxation

Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our share of the domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas). Further, the federal government may adopt tax laws and/or regulations that will possibly materially adversely affect us. For example, tax legislation enacted in December 2017 provides that net operating losses (“NOLs”) arising in tax years ending after December 31, 2017 are only deductible to the extent of 80% of our taxable income in such year. In addition, NOLs can now be carried forward indefinitely, but cannot be carried back. Other measures that have been proposed in the past include the repeal or elimination of percentage depletion and the immediate deduction or write-offs of intangible drilling costs. Because of the speculative nature of potential future changes in federal tax laws, we are unable to determine what effect, if any, future laws would have on product demand or our results of operations. See further discussion of the potential limitations on our ability to utilize NOLs in "Item 1A. Risk Factors" and recent changes to tax laws and regulations in "Note 12. Income taxes" in the Notes to our Consolidated Financial Statements.

U.S. environmental regulations

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Federal environmental statutes to which our domestic activities are subject include, but are not limited to:

the Oil Pollution Act of 1990 (“OPA”);
the Clean Water Act of 1972 (“CWA”);
the Rivers and Harbors Act of 1899;
the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”);
the Resource Conservation and Recovery Act (“RCRA”);
the Clean Air Act (“CAA”);
the Safe Drinking Water Act (“SDWA”);
the Toxic Substances Control Act of 1976 ("TSCA");
the Endangered Species Act of 1973 (the "ESA"); and
the National Environment Policy Act of 1969 (the "NEPA").

These laws and their implementing regulations, as well as analogous state and local laws and regulations, generally restrict pollutants emitted to the air, discharges to surface waters, and disposal or other releases to surface and below ground soils and groundwater.


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In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. For example, the United States Environmental Protection Agency (“EPA”) has identified ensuring environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017-2019. However, the EPA has proposed to transition away from a sector specific initiative for the 2020-2023 fiscal years to a more general focus on significant sources of VOCs.

Our domestic activities are subject to regulations promulgated under federal statutes and comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations and other materials generated by our operations. Administrative, civil and criminal penalties, as well as injunctive relief, may be imposed for non-compliance with environmental laws and regulations. Additionally, these laws and regulations may require the acquisition of permits or other governmental authorizations before we undertake certain activities, limit or prohibit other activities because of protected areas or species, restrict the types of substances used in our drilling operations, impose certain substantial liabilities for the investigation and clean-up of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination, and require substantial expenditures for compliance. We cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Under the CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties; or (3) specified damages, such as loss of use, property damage and natural resource damages. The scope of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA imposes restrictions and permitting requirements for discharges of pollutants as well as certain discharges of dredged or fill material into waters of the United States, including certain wetlands, which may apply to various of our construction activities, as well as requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing discharges to water also may impose restrictions and require varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In 2015, the EPA issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was approved and the current administration moved to stay and replace the rule. On February 14, 2019, the EPA proposed a new rule on federal jurisdiction over the waters of the United States. The comment period on this rule remains open.

CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” or under state law, other specified substances, into the environment. So-called potentially responsible parties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by third parties not under our control, and/or from conditions at third party disposal facilities where materials from operations were sent. Although CERCLA currently exempts petroleum (including oil and natural gas) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot ensure that this exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA or regulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in certain instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that result.


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RCRA and comparable state and local programs impose requirements on the management, generation, treatment, storage, disposal and remediation of both hazardous and nonhazardous solid wastes. Although we believe we utilize operating and waste disposal practices that are standard in the industry, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease, in addition to the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and non-hazardous solid waste in our routine operations. It is possible that certain wastes generated by our operations, which are currently exempt from “hazardous waste” regulations under RCRA, may in the future be designated as “hazardous waste” under RCRA or other applicable state statutes and become subject to more rigorous and costly management and disposal requirements; these wastes may not be exempt under current applicable state statutes. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in a significant increase in our costs to manage and dispose of waste.

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA and analogous state and local laws require certain new and modified sources of air pollutants to obtain permits prior to commencing construction or operation. Smaller sources may qualify for exemption from permit requirements or for more streamlined permitting, for example, through qualifications for permits by rule, standard permits or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional operating permits. Federal and state laws designed to control hazardous (i.e., toxic) air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to suspend or forgo construction, modification or operation of certain air emission sources.

The EPA has issued final rules to subject oil and natural gas productions, storage, processing and transmission operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”), both programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, which became effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect these rules and amendments will have on our business.

The EPA has adopted rules to regulate methane emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. The rules amend the air emission rules for oil and natural gas sources and natural gas processing and transmission facilities to include new standards for methane. In September 2018, the EPA proposed changes to the previously-adopted methane emissions rules to reduce regulatory burdens and harmonize federal and state requirements by reducing the frequency for monitoring methane leaks and increase the time allowed for repair and allowing companies to meet certain state requirements for leaks as an alternative to EPA standards where the state regulations “are at least equivalent” to the EPA’s. The status of future regulation remains unclear, but any changes could require changes to our operations, including the installation of new emission control equipment. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations.

In the most recent Congressional session, a resolution was proposed which aimed to dramatically reduce greenhouse gas emissions, including a transition from fossil fuel. It is unclear what the future of this or other legislation would be. However, such legislation if adopted could have an adverse effect on demand for the oil and natural gas that we produce. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions.

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Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. In addition, GHG regulations could have an adverse effect on demand for the oil and natural gas we produce.

In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will continue to incur costs associated with this reporting obligation.

Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. The United States is one of more than 120 nations having ratified or otherwise consented to the agreement; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. President Trump has announced the United States' intention to withdraw from the Paris Agreement.

In late 2016, the BLM adopted rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. In September 2018, the BLM finalized a rule that eliminated many of the initial restrictions on flaring and venting and modified or replaced others. This rulemaking has been challenged in court and litigation is ongoing. Additional regulations on our air emissions are likely to result in increased compliance costs and additional operating restrictions on our business.

ESA was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

Oil and natural gas exploration and production activities on federal lands may be subject to the NEPA, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we could incur added costs, which may be significant. Reviews and decisions under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. To the extent that our exploration and development plans include leases on federal lands, the NEPA requirements have the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Hydraulic fracturing activities

Over the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing activities in the United States. While hydraulic fracturing is typically regulated by state oil and natural gas commissions in the United States, there have recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.

Nearly all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Our hydraulic fracturing activities are focused in our shale plays in South Texas, East Texas, North Louisiana and Appalachia. Predominantly all of our undeveloped properties would not be economical without the use of hydraulic fracturing to stimulate production from the well.


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Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA currently exempts from regulation the injection of fluids or propping agents (other than diesel fuels) for hydraulic fracturing operations. Congress has periodically considered legislation to amend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and to require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of bills previously introduced before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Many states have considered or adopted legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process or the prohibition of certain hydraulic fracturing activities. These bills, or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance.

In addition, the EPA has recently been taking action to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA's Underground Injection Control Program and has issued guidance regarding its authority over the permitting of these activities. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In 2014, the EPA published an advanced notice of public rulemaking regarding TSCA reporting of the chemical substances and mixture used in hydraulic fracturing.

The BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and tribal lands but, in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. In December 2017, the BLM issued a final rule to rescind the earlier rulemaking on hydraulic fracturing. This rulemaking has been challenged in court and litigation is ongoing.

Local regulations, which may be preempted by state and federal regulations, have included the following which may extend to all operations including those beyond hydraulic fracturing:

noise control ordinances;
traffic control ordinances;
limitations on the hours of operations; and
mandatory reporting of accidents, spills and pressure test failures.

If in the course of our routine oil and natural gas operations, surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, investigation and remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may impose legal liabilities upon us.

If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program complying with current environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation, our assessment regarding the cost of compliance or the extent of liability risks may change in the future.

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OSHA and other regulations

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal OSHA and comparable state statutes, where applicable. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes, where applicable, require that we maintain and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable state requirements.

Title to our properties

When we acquire developed properties we conduct a title investigation, which will most often include either reviewing or obtaining a title opinion. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local real property and/or mineral records. We will conduct title investigations and, in most cases, obtain a title opinion of local counsel for the drill site before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire marketable title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

Our properties are generally burdened by:

customary royalty and overriding royalty interests;
liens incident to operating agreements; and
liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

We believe that none of these burdens materially detract from the value of our properties or materially interfere with property used in the operation of our business. In addition to the foregoing listed burdens, substantially all of our properties have been pledged as collateral under the DIP Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans and the Second Lien Term Loans.

Operational factors and insurance

Oil and natural gas exploration and development involve a high degree of risk. In the event of explosions, environmental damage, or other accidents such as well fires, blowouts, equipment failure and human error, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in the loss of oil and natural gas properties. As is common in the oil and natural gas industry, we are not fully insured against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our operating results, financial position or cash flows. For further discussion on risks see “Item 1A. Risk Factors - We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flows.”  

We currently carry automobile liability, general liability and excess liability insurance with a combined annual limit of $72 million per occurrence and in the aggregate. These insurance policies contain maximum policy limits and deductibles ranging from $1,000 to $25,000 that must be met prior to recovery, and are subject to customary exclusions and limitations. Our automobile and general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if the automobile and general liability insurance per occurrence limit is reached. Further, we currently carry $45 million of pollution coverage, $25 million of well control (blowout) coverage, property insurance in the amount of $178 million in respect of wellhead, surface equipment, tanks, and miscellaneous items and scheduled oil lease roads coverage with deductibles ranging from $25,000 to $500,000.

We require our third-party contractors to sign master service agreements in which they generally agree to indemnify us for the injury and death of the service provider's employees as well as contractors and subcontractors that are hired by the service provider. Similarly, we agree to indemnify our third-party contractors against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property.

Our third-party contractors that perform hydraulic fracturing operations for us sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. We believe that our general liability, excess

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liability and pollution insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policies generally will not cover fines and penalties. Further, these policies may not cover the costs and expenses related to government-mandated environmental clean-up responsibilities, or may do so on a limited basis.

Our employees

As of December 31, 2018, we employed 153 persons. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be satisfactory. We also utilize the services of independent consultants and contractors.

Forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended ("Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended ("the Exchange Act"). These forward-looking statements relate to, among other things, the following:

our future financial and operating performance and results;
our business strategy;
market prices;
our future use of derivative financial instruments;
our liquidity and capital resources; and
our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “potential,” “project,” “budget” and other similar words to identify forward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections of results of operations or our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Annual Report on Form 10-K and the documents incorporated herein by reference, including, but not limited to:

bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations, including the actions of the Court and our creditors;
our ability to enter into transactions as a result of our Chapter 11 filing, including commodity derivative contracts with financial institutions and services with vendors;
our future cash flows and the adequacy to fund the significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;
our ability to obtain the requisite number of votes required to obtain confirmation of a plan of reorganization;
our ability to maintain compliance with debt covenants and to meet debt service obligations associated with the DIP Credit Agreement;
our ability to obtain exit financing in order to consummate a plan of reorganization;
future capital requirements and availability of financing, including limitations on our ability to incur certain types of indebtedness under our debt agreements and to refinance or replace existing debt obligations;
fluctuations in the prices of oil and natural gas;
the availability of oil and natural gas;
disruption of credit and capital markets and the ability of financial institutions to honor their commitments;
estimates of reserves and economic assumptions, including estimates related to acquisitions and dispositions of oil and natural gas properties;
geological concentration of our reserves;
risks associated with drilling and operating wells;
exploratory risks, including those related to our activities in shale formations;
discovery, acquisition, development and replacement of oil and natural gas reserves;
timing and amount of future production of oil and natural gas;
availability of drilling and production equipment;
availability of water, sand and other materials for drilling and completion activities;

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marketing of oil and natural gas;
political and economic conditions and events in oil-producing and natural gas-producing countries;
title to our properties;
litigation;
competition;
our ability to attract and retain key personnel;
general economic conditions, including costs associated with drilling and operations of our properties;
environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;
receipt and collectability of amounts owed to us by purchasers of our production;
potential acts of terrorism;
our ability to manage joint ventures with third parties, including the resolution of any material disagreements and our partners’ ability to satisfy obligations under these arrangements;
actions of third party co-owners of interests in properties in which we also own an interest;
fluctuations in interest rates;
our ability to effectively integrate companies and properties that we acquire;
our ability to execute our business strategies and other corporate actions; and
our ability to continue as a going concern.

We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements included in this Annual Report on Form 10-K. The risk factors noted in this Annual Report on Form 10-K provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please see “Item 1A. Risk Factors” for a discussion of certain risks related to our business, indebtedness and common shares.

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital from the DIP Credit Agreement and other sources. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, Liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Glossary of selected oil and natural gas terms

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.
2-D seismic. Geophysical data that depicts the subsurface strata in two dimensions.
3-D seismic. Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.
Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.
Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.
Bbtu. One billion British thermal units.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy

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equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas.
Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.
Deterministic method. The method of estimating reserves or resources when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
 
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole; Dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible. As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploitation. The continuing development of a known producing formation in a previously discovered field. To maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.
Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Fracture stimulation. A stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulate hydrocarbon production.
Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Held-by-production. A provision in an oil, natural gas and mineral lease that perpetuates a company's right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or natural gas.
Horizontal wells. Wells drilled at angles greater than 70 degrees from vertical.
Initial production rate. Generally, the maximum 24 hour production volume from a well.
Mbbl. One thousand stock tank barrels.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Mmbbl. One million stock tank barrels.
Mmbtu. One million British thermal units.
Mmcf. One million cubic feet of natural gas.
Mmcf/d. One million cubic feet of natural gas per day.
Mmcfe. One million cubic feet of natural gas equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate

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energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas. 
Mmcfe/d. One million cubic feet of natural gas equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Net acres or net wells.  Exists when the sum of fractional ownership interests owned in gross acres or gross wells equals one. We compute the number of net wells by totaling the percentage interest we hold in all our gross wells.
NYMEX. New York Mercantile Exchange.
NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
Overriding royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.
Pad drilling. The drilling of multiple wells from the same site.
Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.
Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated.
Probabilistic method. The method of estimation of reserves or resources when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Productive well. A productive well is a well that is not a dry well.
Proved Developed Reserves. These reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved Reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with Reasonable Certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with Reasonable Certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with Reasonable Certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with Reasonable Certainty.
 Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the Reasonable Certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

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Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes Reasonable Certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing Reasonable Certainty.
Recompletion. An operation within an existing well bore to make the well produce oil and/or natural gas from a different, separately producible zone other than the zone from which the well had been producing.
Reasonable Certainty. If deterministic methods are used, Reasonable Certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources. Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Shut-in well. A producing well that has been closed down temporarily for, among other things, economics, cleaning out, building up pressure, lack of a market or lack of equipment.  
Spud. To start the well drilling process.
Standardized Measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows are estimated by applying the simple average spot prices for the trailing 12 month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for price differentials, to the estimated future production of year-end Proved Reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
Stock tank barrel. 42 U.S. gallons liquid volume.
Tcf. One trillion cubic feet of natural gas.
Tcfe. One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price for six Mcf of natural gas.
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.

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Working interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.
Workovers. Operations on a producing well to restore or increase production.
Available information

We make available, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports on our website at www.excoresources.com as soon as reasonably practicable after those reports and other information are electronically filed with, or furnished to, the SEC.

Item 1A.
Risk Factors

The risk factors noted in this section and other factors noted throughout this Annual Report on Form 10-K, including those risks identified in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this Annual Report on Form 10-K.

Risks Relating to Our Restructuring

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. Our business and operations will be subject to various risks for the duration of the Chapter 11 proceedings, including, but not limited to, the following:

our ability to continue as a going concern;
our ability to develop, file and consummate a Chapter 11 plan of reorganization;
our ability to obtain Court, creditor and regulatory approval of a Chapter 11 plan of reorganization in a timely manner;
our ability to obtain consents or waivers to further extend the DIP Facilities beyond the scheduled maturity date of May 22, 2019 or refinance the DIP Facilities if we are unable to consummate a plan of reorganization in a timely manner;
our ability to obtain Court approval with respect to motions in the Chapter 11 Cases and the outcomes of Court rulings and of the Chapter 11 Cases in general;
the ability of third parties to file motions in our Chapter 11 Cases, which may interfere with our business operations or our ability to propose and/or complete a Chapter 11 plan of reorganization;
significant costs related to the Chapter 11 Cases and related litigation;
our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers, as well as our ability to maintain contracts that are critical to our operations;
a loss of, or a disruption in the materials or services received from suppliers, contractors or service providers with whom we have commercial relationships;
potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees;
significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; and
our ability to fund and execute our business plan and our ability to obtain any necessary financing for our business on acceptable terms or at all.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition. Also,

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pursuant to the Bankruptcy Code, we need Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common shares in our capital structure. As a result, we believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares are not expected to be entitled to any recovery. The March 2019 Plan would result in our common shares being canceled, discharged, released and extinguished without the holders thereof receiving any distribution. As a result, any trading in our common shares during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common shares.

Operating under Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. We have been operating under Court protection since our initial filing for relief under Chapter 11 of the Bankruptcy Code in January 2018, and this prolonged period of operations under Court protection has had, and is expected to continue to have, a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the proceedings related to the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and seek to establish alternative commercial relationships.

During the course of the Chapter 11 Cases, we have been required, and expect that we will continue to be required, to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. We have incurred $67.8 million in legal and professional fees related to the Chapter 11 Cases for the period from the Petition Date to December 31, 2018. Furthermore, we have experienced, and expect to continue to experience, significant costs and delays due to litigation during the Chapter 11 Cases. These fees and expenses have forced us to divert our capital resources away from capital expenditures to grow our business.

During the pendency of the bankruptcy proceedings, our Liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement providing for $250.0 million of debtor-in-possession financing. The proceeds from the DIP Facilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and are expected to provide additional liquidity to fund our operations during the Chapter 11 Cases. The DIP Facilities mature on May 22, 2019 and may not be sufficient to support our day-to-day operations in the event of a prolonged restructuring process and we may be required to seek additional debtor-in-possession financing to fund our operations. A further extension of the DIP Facilities beyond the scheduled maturity date would require a waiver or consent from the DIP Lenders. If we are required to seek additional financing, we may not be able to obtain such financing on favorable terms or at all. See further discussion regarding the impact of the maturity of the DIP Facilities in "Item 1A. Risk Factors - We have substantial liquidity needs and may be required to seek additional financing if we experience a prolonged bankruptcy process. If we are unable to maintain adequate liquidity, we may not be able to obtain financing on satisfactory terms". As a result, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any claims and securities in the Debtors could become further devalued or become worthless.

We cannot predict the ultimate outcome for the liabilities that will be subject to a plan of reorganization. Even if a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11.

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We are subject to the risks and uncertainties associated with our exclusive right to file a plan of reorganization.

At the outset of the Chapter 11 proceedings, the Bankruptcy Code provides debtors-in-possession the exclusive right to file and solicit acceptance of a plan of reorganization for the first 120 days of the bankruptcy case, subject to extension at the discretion of the court.  All other parties are prohibited from filing or soliciting a plan of reorganization during this period.  Our initial filing exclusivity period was set to expire on May 15, 2018 and the solicitation exclusivity period was set to expire on July 14, 2018.  The Court has approved multiple extensions to the filing exclusivity period and the solicitation exclusivity period. The most recent extensions were approved by the Court on February 15, 2019, which extended the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019. If the Court terminates that right or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan in order to achieve our stated goals. The possible decision of creditors and/or other third parties, whose interest may be inconsistent with our own, to file alternative plans of reorganization could further protract the Chapter 11 proceedings, leading us to continue to incur significant professional fees and costs. Because of these risks and uncertainties associated with the termination or expiration of our exclusivity rights, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 cases may have on our corporate or capital structure.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Court protection as a viable entity, we must meet certain statutory requirements with respect to a Chapter 11 plan of reorganization, including obtaining the requisite acceptances of such a plan, and certain other statutory conditions for confirmation of such a Chapter 11 plan, which have not occurred to date. 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.

We have not received consents from any creditors in support of the March 2019 Plan. Therefore, we may not receive the requisite acceptances to confirm the March 2019 Plan. Even if the requisite acceptances of a plan are received, the Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, or common shares).

If a Chapter 11 plan of reorganization is not ultimately confirmed by the Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims. Our creditors would likely incur significant costs in connection with developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the current debt holders, various statutory committees or other stakeholders. If we are unable to confirm the March 2019 Plan and an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity. There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or market conditions deteriorate, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to:

changes in the price of oil and natural gas, including our increased exposure since none of our estimated future production is currently covered by commodity derivative contracts;
our ability to obtain adequate liquidity and financing sources, including acceptable terms for any new debt instruments contemplated by a plan of reorganization;

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our ability to maintain the confidence of our vendors, customers and joint interest partners in our viability as a continuing entity and to attract and retain sufficient business with them;
our ability to retain key employees; and
the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets.

Adverse changes in any of these factors could materially affect the successful reorganization of our businesses. Accordingly, any Chapter 11 plan of reorganization may not enable us to achieve our goals or continue as a going concern.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, changes in prices for oil and natural gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that any plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other means to fund our business after the completion of the Chapter 11 process. Adequate funds may not be available when needed or may not be available on favorable terms.

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.

The availability of borrowings under the DIP Credit Agreement is essential to our ability to fund our operations during the Chapter 11 Cases. The DIP Credit Agreement includes certain affirmative and negative covenants, including, among other covenants customary in similar reserve-based credit facilities and debtor-in-possession financings, requirements to maintain a minimum level of liquidity and limit our aggregate disbursements to certain thresholds compared to the 13-week cash flow forecasts provided to the DIP Lenders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations, development activities and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. 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.

If we violate any provisions of our such financing agreements that are not cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. 

We have substantial liquidity needs and may be required to seek additional financing if we experience a prolonged bankruptcy process. If we are unable to maintain adequate liquidity, we may not be able to obtain financing on satisfactory terms.

Our principal sources of Liquidity historically have been internally generated cash flows from operations, borrowings under certain credit agreements, issuances of debt securities, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. Our Liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability to comply with the terms and conditions of any post-petition financing and cash collateral order entered by the Court in connection with the Chapter 11 Cases, (ii) our ability to maintain adequate cash on

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hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to maintain adequate Liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control.

We face uncertainty regarding the adequacy of our Liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases. We cannot provide assurance that our Liquidity will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11 Cases until we are able to emerge from our Chapter 11.

The DIP Facilities are currently set to mature on May 22, 2019. In order to repay the DIP Facilities at maturity, we currently expect that we would need to seek additional financing, sell assets, refinance or restructure the DIP Facilities prior to maturity or extend the maturity date of the DIP Facilities. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Although we have previously extended the maturity date of the DIP Facilities, the DIP Lenders may not agree to any further extensions. Our ability to consummate the March 2019 Plan in a timely manner, if at all, is subject to significant risk since we have not received consents from any creditors in support of the March 2019 Plan. As a result, it is unlikely that we will be able to consummate a plan of reorganization prior to the maturity of the DIP Facilities. Therefore, our long-term liquidity and the adequacy of our capital resources are highly uncertain at this time.

Upon emergence from bankruptcy, the composition of our board of directors will change significantly.

The composition of our board of directors is expected to change significantly following the Chapter 11 Cases. Any new directors may have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Court may convert our Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations. In addition, if the Chapter 11 Cases are converted to cases under Chapter 7, that would constitute an event of default under the DIP Credit Agreement.

As a result of the Chapter 11 Cases, our historical financial information may be volatile and not be indicative of our future financial performance.

During the Chapter 11 Cases, we expect our financial results under U.S. GAAP to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our Consolidated Financial Statements. As a result, our historical financial performance may not be indicative of our financial performance after the date of the bankruptcy filing.

Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Court. Under fresh-start accounting rules that may apply to us upon the effective date of a Chapter 11 plan, our assets and liabilities would be adjusted to fair value, which could have a significant impact on our financial statements. Accordingly, if fresh-start accounting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.


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Transfers of our equity, or issuances of equity in connection with our Chapter 11 Cases, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have NOLs of approximately $2.2 billion as of December 31, 2018. Our ability to utilize our NOLs to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in Section 382 of the U.S. Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning five percent or more of a corporation’s common stock ("Substantial Shareholder") have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period.

We received relief from the Court to establish notice and sell-down procedures for trading of our common shares in order to provide us with the ability to formulate a plan of reorganization that preserves our tax attributes. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person or entity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.

Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under Section 382 of the U.S. Internal Revenue Code, absent an application exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.  If an ownership change occurs and our NOLs are subject to the Section 382 limitation, this could adversely impact our future cash flows if we have taxable income and are not able to offset it through the utilization of our NOLs. See further discussion of the impact of the restructuring on our tax attributes as part of "Note 12. Income taxes" in the Notes to our Consolidated Financial Statements.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivative contracts and we may not be able to enter into commodity derivative contracts covering our estimated future production on favorable terms or at all.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. None of our estimated future production is currently covered by commodity derivative contracts; therefore, we will continue to be significantly impacted by changes in commodity prices if we cannot or choose not to enter into commodity derivative contracts in the future. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

We have and may continue to experience increased levels of employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we have and may continue to experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, Liquidity and results of operations.


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Risks Relating to Our Business

Oil and natural gas prices, which are subject to fluctuations, have declined substantially from historical highs. Reductions in oil and natural gas prices have, and may in the future, adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.

Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. We are particularly dependent on prices for natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including, but not limited to:
the domestic and foreign supply of oil and natural gas;
weather conditions;
the price and quantity of imports and exports of oil and natural gas;
political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the actions of the OPEC and other significant oil and natural gas producing nations;
domestic and international government regulation, legislation and policies, including levying tariffs on oil and natural gas imports;
the level of global oil and natural gas inventories;
technological advances affecting energy consumption;
the price and availability of alternative fuels and other energy sources; and
overall economic conditions.

Oil and natural gas prices are currently depressed compared to recent historical levels; however, they may never return to historical highs or remain at a level that allows us to economically operate our business. Prices of oil and natural gas have historically been extremely volatile and we expect this volatility to continue.

During 2018, the NYMEX Henry Hub natural gas price fluctuated from a high of $6.88 per Mmbtu to a low of $2.48 per Mmbtu, while the NYMEX WTI crude oil price ranged from a high of $76.41 per Bbl to a low of $42.53 per Bbl. For the five years ended December 31, 2018, the NYMEX Henry Hub natural gas price ranged from a high of $7.94 per Mmbtu to a low of $1.49 per Mmbtu, while the NYMEX WTI crude oil price ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl.

On December 31, 2018, the spot market price for natural gas at Henry Hub was $3.07 per Mmbtu, a 3% increase from December 31, 2017. On December 31, 2018, the spot market price for crude oil at Cushing was $45.41 per Bbl, a 25% decrease from December 31, 2017. For 2018, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $66.78 per Bbl and $2.85 per Mcf, respectively, compared with 2017 average realized prices of $49.82 per Bbl and $2.51 per Mcf, respectively.

Our revenues, cash flow and profitability, as well as our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, depend substantially upon oil and natural gas prices. Any sustained reductions in oil and natural gas prices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commercially recoverable. Depressed oil and natural gas prices and reductions in our reserves could have other adverse consequences, including our ability to obtain the exit financing required to consummate a plan of reorganization. Additionally, further or continued declines in prices could result in additional non-cash charges to earnings due to impairments to our oil and natural gas properties.

In light of the depressed commodity price environment, there is risk that, among other things:

third parties’ confidence in our commercial or financial ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy;
it may become more difficult to retain, attract or replace key employees;
employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and
our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.


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The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.

Changes in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a premium or discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition. We have experienced significant volatility in our price differentials including crude oil production from the Eagle Ford shale and natural gas production from certain areas in Appalachia. Our crude oil production from the Eagle Ford shale is currently sold at a price based on the WTI index plus or minus the differential to indices correlated to the Louisiana Light Sweet index. During 2018, the monthly average of this differential ranged from a high of WTI plus $4.99 per barrel to a low of WTI less $0.99 per barrel. Our natural gas production from the Marcellus shale in Northeast Pennsylvania is sold at a price based on a Platts index that represents value into the Transco Leidy Pipeline. Due to the high levels of production in this region without sufficient pipeline capacity or infrastructure to the Northeast United States markets, the monthly average of this differential during 2018 ranged from a low of NYMEX less $0.31 per Mmbtu to a high of NYMEX less $1.38 per Mmbtu. These differentials vary depending on factors such as supply, demand, pipeline capacity, infrastructure and weather. These differentials continue to be volatile; however, the differentials in the region have the potential to be favorably impacted by the expansion of infrastructure and other sources of demand for natural gas in the Northeast region in future years. 

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements or infrastructure may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.

Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third-parties. Our failure to obtain these services on acceptable terms could have a material adverse effect on our business. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs, outages caused by accidents or other events, or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. We may be required to shut-in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines, gathering systems or trucking capacity. A portion of our production may also be interrupted, or shut-in, from time to time for numerous other reasons, including as a result of accidents, excessive pressures, maintenance, weather, field labor issues or other disruptions of service. Curtailments and disruptions may last from a few days to several months, and we have no control over when or if third-party facilities are restored.

We have experienced production curtailments in our producing regions resulting from offsetting fracturing stimulation operations. As we have increased our knowledge of our shale properties, we have begun to shut-in production on adjacent wells when conducting completion operations. Due to the high production capabilities of these wells, these volumes can be significant. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.

These factors and the availability of markets are beyond our control. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities or lack of availability of transportation would interfere with our ability to market our oil and natural gas production, and could have a material adverse effect on our cash flow and results of operations.

Our oil production in the South Texas region may be curtailed if we are not able to find an operational or commercial solution for the associated natural gas production.

In our South Texas region, the primary purchaser of our natural gas allegedly terminated a long-term natural gas sales contract on May 31, 2017. As a result, our ability to transport or sell the natural gas from this region continues to be limited due to the existing infrastructure and we may experience significant curtailments of production in the future if we cannot find an

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operational or commercial solution. After the alleged termination of the long-term natural gas sales contract, we have either sold natural gas on short-term sales contracts or flared natural gas in order to avoid significant curtailments of our oil production. However, our ability and the costs associated with entering into natural gas sales contracts in the future are highly uncertain.

In January 2018, we commenced the flaring of natural gas produced in our South Texas region pursuant to temporary flare permits. We submitted a request to the Texas Railroad Commission for an extension of the permits to continue the aforementioned flaring of natural gas for up to two years (the “Flaring Application”). We went before the Texas Railroad Commission at a hearing regarding the Flaring Application in May 2018 and expect that a final ruling will be issued during 2019. See further discussion in “Item 3. Legal Proceedings”. If the Flaring Application is denied or, in the future, we are unable, for any sustained period, to secure acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut-in or curtail production of both oil and natural gas from the affected wells in the South Texas region. Any such shut-in or curtailment or an inability to obtain acceptable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our cash flows and results of operations. We continue to evaluate alternatives, including construction of a Company-owned gathering system or the negotiation of a new gathering agreement.

We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas or reduce the volume of oil and natural gas that they purchase from us.

Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. We are managing our credit risk as a result of the current commodity price environment through the attainment of financial assurances from certain customers. In addition, if any of our significant customers cease to purchase our oil or natural gas or reduce the volume of the oil or natural gas that they purchase from us, the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas. We have filed a lawsuit against a subsidiary of Shell regarding their failure to remit payment under certain natural gas sales agreements in the East Texas and North Louisiana regions, see further discussion in "Item 3. Legal proceedings".

There are risks associated with our drilling activity that could impact our results of operations and financial condition. Our ability to develop properties in new or emerging formations may be subject to more uncertainties than drilling in areas that are more developed or have a longer history of established production.

Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic and other technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. We have experienced some delays in contracting for drilling rigs and in obtaining fracture stimulation crews and materials. Also, we may experience issues with the availability of water and sand used in our drilling and hydraulic fracturing activities. All of these risks could adversely affect our results of operations and financial condition.

The results of our drilling in new or emerging formations, including our properties in shale formations, are more uncertain initially than drilling results in areas that are developed, have established production or where we have a longer history of operation. Because new or emerging formations have limited or no production history, we are less able to use past drilling results in those areas to help predict future drilling results. Our experience with horizontal drilling in these areas to date, as well as the industry’s drilling and production history, while growing, is limited. The ultimate success of these drilling and completion techniques will be better evaluated over time as more wells are drilled and production profiles are better established. We have implemented several initiatives to manage our base production and minimize the decline from our shale properties. If these initiatives are not successful and we are required to incur significant expenditures to manage our base production, this could negatively impact our production and cash flows from operations.

If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, and/or natural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material impairments of undeveloped properties and the value of our undeveloped acreage could decline in the future, which could have a material adverse effect on our business and results of operations.


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Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on the acreage.

Leases on oil and natural gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to our operations, our drilling plans for these areas are subject to change.

We conduct a substantial portion of our operations through joint interest and joint venture arrangements. Material disagreements with our partners could have a material adverse effect on the success of these operations, our financial condition and our results of operations. Furthermore, the actions taken by our partners could prevent or alter our development plans.

We conduct a substantial portion of our operations through joint interest and joint venture arrangements with third parties. In many instances, we depend on these third parties for elements of these arrangements, such as payments of substantial development and other costs. The performance of these third party obligations or the ability of third parties to meet their obligations under these arrangements is outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our current or future joint interest or joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights, which may cause disputes among our partners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations.

Such arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

our partners may share certain approval rights over major decisions;
the possibility that our partners might become insolvent or bankrupt, leaving us liable for their shares of joint interest or joint venture liabilities;
the possibility that we may incur liabilities as a result of an action taken by our partners;
partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;
disputes between us and our partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business; and
that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture and an impasse could be reached that might have a negative influence on our investment in the joint venture.

The failure to resolve disagreements with our partners could adversely affect our ability to transact the business that is the subject of such arrangement, which would in turn negatively affect our financial condition and results of operations.

The owners of working interests may not consent to the development of certain properties that we operate, which may require us to assume their share of the working interest during the development and a period after the well is on production. This may require us to expend additional capital that was not anticipated as part of our development plans and assume additional risks associated with the development and future performance of the properties. The owners of working interests in certain properties that we operate may also hold rights within the respective operating agreements that could prevent us from performing additional development activities on the properties such as recompletions and other workovers without their consent.

We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.

Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire or develop additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale. If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. We may be unable to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.


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Acquisitions, development drilling and exploratory drilling are the main methods of replacing reserves. However, development and exploratory drilling operations may not result in any increases in reserves for various reasons. Our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, exploration, development and exploitation activities.

Our future success will depend on the success of our acquisition, exploration, development and exploitation activities. Our decisions to purchase, explore, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. These decisions could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves, our financial condition and the value of our common shares.

Numerous uncertainties are inherent in estimating quantities of Proved Reserves, including many factors beyond our control. This Annual Report on Form 10-K contains estimates of our Proved Reserves and the PV-10 and Standardized Measure of our Proved Reserves. These estimates are based upon reports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated Proved Reserves.

The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue and such estimates prepared by different engineers or by the same engineers at different times, may vary substantially.

Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and Standardized Measure described in this Annual Report on Form 10-K, and our financial condition. In addition, our reserves, the amount of PV-10 and Standardized Measure may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices, decisions and assumptions made by engineers and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes and values of our reserves. Similarly, a decline in market prices for oil or natural gas may adversely affect our PV-10 and Standardized Measure. Any of these negative effects on our reserves or PV-10 and Standardized Measure may negatively affect the value of our common shares.

Impairments of our asset values could have a substantial negative effect on our results of operations and net worth.

We follow the full cost method of accounting for our oil and natural gas properties. Depending upon oil and natural gas prices in the future, and at the end of each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required to record an impairment to the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. We have in the past experienced, and may experience in the future, ceiling test impairments with respect to our oil and natural gas properties. As discussed above, we are also currently in Chapter 11 proceedings and, upon the approval of a Chapter 11 plan, may be required to apply fresh-start accounting principles that may cause us to experience additional impairments. See “Item 1A. Risk Factors - As a result of the Chapter 11 cases, our historical financial information may be volatile and not be indicative of our future financial performance” for additional information.

Our evaluation of impairment is based upon estimates of Proved Reserves. The value of our Proved Reserves may be lowered in future periods as a result of a decline in prices of oil and natural gas, a downward revision of our oil and natural gas reserves or other factors. As a result, our evaluation of impairment for future periods is subject to 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. Because several of these factors are beyond our control, we cannot accurately predict or control

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the amount of ceiling test impairments in future periods. Future ceiling test impairments could negatively affect our results of operations and net worth.

We did not recognize any impairments to our proved oil and natural gas properties for the years ended December 31, 2018 and 2017. We may have additional impairments of our oil and natural gas properties in future periods if the cost of our unamortized proved oil and natural gas properties exceeds the limitation under the full cost method of accounting. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting unit exceeds the estimated fair value of the reporting unit, an impairment charge will occur, which would negatively impact our results of operations and net worth. As a result of our testing of goodwill for impairment, we did not record an impairment charge for the years ended December 31, 2018 and 2017.

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

fires, explosions and blowouts;
pipe failures;
abnormally pressured formations; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

We have in the past experienced some of these events during our drilling, production and midstream operations. These events may result in substantial losses to us from:

injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;
pollution or other environmental damage;
environmental clean-up responsibilities;
regulatory investigation;
penalties and suspension of operations; or
attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these potential losses or liabilities. Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage for certain drilling activities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our results of operations and cash flow.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, production and sale of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. For additional information, see “Item 1. Business - Applicable Laws and Regulations".


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Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures and could negatively impact production.

Our operations are subject to numerous complex U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements.

In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. For example, the EPA has identified ensuring environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 - 2019. However, the EPA has proposed to transition away from a sector specific initiative for the 2020-2023 fiscal years to a more general focus on significant sources of VOCs.

Compliance with environmental laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations as well as associated natural resource damages, or the issuance of injunctive relief. Any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Changes to the requirements for drilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.

In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent than those currently in effect. For example, the regulation of GHG emissions by the EPA or by various states in the areas in which we conduct business could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its regulations under the CAA, SDWA, RCRA, TSCA and CWA.

The environmental laws and regulations to which we are subject may, among other things:

require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;
restrict the types, quantities and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other “waters of the United States,” threatened and endangered species habitats and other protected areas;
require remedial measures to mitigate pollution from current or former operations, such as cleaning up spills, dismantling abandoned facilities, pit closure or plugging abandoned wells;
require additional control and monitoring devices on equipment; and
impose substantial liabilities for pollution resulting from our operations.

Our operations may be impacted by recent or changing regulatory standards. For example, the EPA issued effluent limitation guidelines limiting our ability to dispose of waste water from hydraulic fracturing activities into publicly owned wastewater treatment systems. The EPA and state regulators are also reviewing the practices for the disposal of solid waste in surface impoundments from exploration and production facilities under Subtitle D of RCRA and may continue to refine those requirements. The EPA and state regulators are also expanding National Pollutant Discharge Elimination System permitting for storm water discharges at drilling sites.

Changes in regulation can also occur at a state or local level. For example, the State of Pennsylvania Department of Environmental Protection is updating oil and gas regulations which include more stringent permitting requirements, waste handling disposal and water restoration requirements. Some localities, for example in Texas, are enacting water usage restrictions that may impact oil and gas exploration. In addition, some states have considered, and notably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control of GHG emissions.


40



The implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.

GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production. In the most recent Congressional session, a resolution was proposed which aimed to dramatically reduce GHG emissions, including a transition from fossil fuel. It is unclear what the future of this or other legislation would be. However, such legislation if adopted could have an adverse effect on demand for the oil and natural gas that we produce.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the U.S. Supreme Court struck down GHG permitting requirements for GHG as a stand-alone pollutant, it upheld the EPA’s authority to control GHG emissions when a source has to secure a major source permit to control the emissions of other criteria pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. Additionally, the EPA established GHG reporting requirements for a broad range of sources, including in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor record and report GHG emissions associated with our operations.

As part of a move to reduce GHG emissions, the EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. The rules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes.  The grouping together of sources may cause a group of sources to be treated as a “major source” and face enhanced regulation under federal environmental laws, including the CAA.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Most hydraulic fracturing (other than hydraulic fracturing using diesel) is exempted from regulation under the SDWA. Congress has considered legislation to amend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Many states have adopted or are considering legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process. Such bills or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we have properties, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program (“UIC”) and has issued guidance regarding its authority over the permitting of these activities. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. If this assessment results in additional regulatory scrutiny, it could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

41




These new initiatives related to hydraulic fracturing may increase our cost of disposal and impact our business operations and could cause our hydraulic fracturing activities to become subject to additional permit requirements or operations restrictions which could lead to permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.

The EPA has adopted rules to limit air emissions from oil and gas operations, subjecting oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAPS programs under the CAA. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. The implementation of these new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. There may also be further refinement to existing NSPS standards for VOCs as data is gathered about the implementation of those requirements.

We operate in a litigious environment.

Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations could impact our future operations and financial condition. In addition, we are defendants in numerous cases involving claims by landowners for surface or subsurface damages arising from our operations and for claims by unleased mineral owners and royalty owners for unpaid or underpaid revenues customary in our business. We incur costs in defending these claims and from time to time must pay damages or other amounts due. Such legal disputes can also distract management and other personnel from their primary responsibilities. For additional information on our significant litigation matters, see “Item 3. Legal Proceedings" and "Note 8. Commitments and contingencies” in the Notes to our Consolidated Financial Statements.

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

As an oil and natural gas production company, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. The implementation of additional procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

There are inherent limitations in all internal controls over financial reporting, and misstatements due to error or fraud may occur and not be detected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our chief financial officer and chief accounting officer, do not expect that our internal controls and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent

42



limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of our company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

The Consolidated Financial Statements included herein contain disclosures that express substantial doubt about our ability to continue as a going concern, indicating the possibility that we may not be able to operate in the future.

The Consolidated Financial Statements included herein 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 Consolidated Financial Statements do not reflect any adjustments that might result from the outcome of our Chapter 11 proceedings. Our level of indebtedness has adversely impacted and is continuing to adversely impact our financial condition. 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.

See further discussion regarding our ability to continue as a going concern as part of "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements.

Risks Relating to Our Common Shares

Our common shares are no longer listed on a national securities exchange and were deregistered under the Exchange Act, which may have a negative impact on our share price, volatility and Liquidity.

Since December 27, 2017, our common shares have been trading over the counter on the OTC Pink Marketplace under the ticker symbol “XCOO.” Our common shares continue to trade under that symbol with the added designation of “Q” to symbolize that we are currently in bankruptcy proceedings.

Our bankruptcy proceedings, as well as the delisting of our common shares from the NYSE and commencement of trading on the OTC Pink Marketplace, has resulted and may continue to result in a significant reduction in some or all of the following, each of which could have a material adverse effect on our shareholders:

the liquidity of our common shares;
the market price of shares of our common shares;
our ability to obtain financing for the continuation of our operations;
the number of institutional and other investors that will consider investing in shares of our common shares;
the number of market makers in our common shares;
the availability of information concerning the trading prices and volume of our common shares; and
the number of broker-dealers willing to execute trades in our common shares.

There is no assurance that we will continue to trade on the OTC Pink Marketplace as we are dependent on one or more market makers establishing a market for our common shares, and even if they continue to do so, there can be no assurance that an active trading market will be maintained. Broker-dealers may decline to trade in the OTC Pink Marketplace because (1) the market for such securities is often limited, (2) such securities are generally more volatile, and (3) the risk to investors is generally greater. Selling our shares could be difficult because smaller quantities of shares can be bought and sold, transactions can be delayed and securities analyst and media coverage of us may be reduced. These factors could result in lower prices and larger spreads in the bid and ask prices for shares of our common shares as well as lower trading volume. We cannot provide any assurance that, even if our common shares continue to be listed or quoted on the OTC Pink Marketplace or another market or system, the market for our common shares will be liquid.

On February 15, 2019, we deregistered our common shares under the Exchange Act, which terminated the requirement to publicly file reports including financial statements and other pertinent information about the Company. As a result, our common share price and liquidity of our common shares may be further negatively impacted since there will be significantly less public information about the Company.

43




We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares are not expected to be entitled to any recovery. As a result, we expect that the market for our common shares will be extremely limited during the pendency of our bankruptcy proceedings. See Item "1A. Risk Factors - We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings".

Our common share price may fluctuate or remain significantly depressed throughout the pendency of our bankruptcy proceedings.

Our common shares currently trade on OTC Pink Marketplace but may have severely limited liquidity as a result of our bankruptcy proceedings, among other things. The market price of our common shares has previously experienced significant fluctuations as a result of:

bankruptcy proceedings and the outcome of the Chapter 11 Cases;
dilutive issuances of our common shares;
announcements relating to our business or the business of our competitors;
changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;
actual or anticipated quarterly variations in our operating results;
conditions generally affecting the oil and natural gas industry;
the success of our operating strategy; and
the operating and share price performance of other comparable companies.

Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common shares. The price of our common shares may fluctuate significantly in the future as a result of these or other factors. However, we currently believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares are not expected to be entitled to any recovery. As a result, the market price of our common shares may remain significantly depressed during the pendency of our Chapter 11 proceedings. See "Item 1A. Risk Factors - We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings".

Item 1B.
Unresolved Staff Comments

None.

Item 2.
Properties

Corporate offices

We lease office space in Dallas, Texas. We also have small offices for technical and field operations in Texas, Louisiana and Pennsylvania. The table below summarizes our material corporate leases.
Location
 
Approximate square footage
 
Approximate remaining monthly payment
 
Expiration
Dallas, Texas
 
48,000

 
$
95,000

 
December 31, 2022

Other

We have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity in “Item 1. Business” of this Annual Report on Form 10-K.


44



Item 3.
Legal Proceedings

Bankruptcy proceedings under Chapter 11

On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. See further discussion in "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements.

Enterprise and Acadian contract litigation

During the third quarter of 2016, a dispute arose regarding our sales and transportation contracts with Enterprise Products Operating LLC ("Enterprise") and Acadian Gas Pipeline System ("Acadian"), respectively. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). In August 2016, each of EXCO and Enterprise did not remit certain payments allegedly due under the parties’ respective agreements. EXCO’s subsidiary, Raider, notified Enterprise that the agreements were in default, and subsequently terminated the agreements. Enterprise disputed our right to terminate the agreements, and commenced litigation at Enterprise Products Operating LLC and Acadian Gas Pipeline System v. EXCO Operating Company, LP, EXCO Partners OLP GP, LLC, Raider Marketing, LP, and Raider Marketing GP, LLC No. 2016-60848 157th Judicial District, Harris County, Texas, and subsequently joined Bluescape and two of our officers, Harold Hickey and Steve Estes. In October 2016, we filed counterclaims against Enterprise and Acadian in the state court action. The suit was automatically stayed pursuant to the Bankruptcy Code upon the commencement of the bankruptcy cases.

On February 12, 2018, Enterprise filed a motion in the Court seeking to lift the automatic stay to continue the suit in state court, and on March 9, 2018, Enterprise filed a motion in the state court seeking to sever the litigation against Bluescape from the litigation against us and our officers so it could proceed despite the automatic stay. On March 19, 2018, we filed a motion seeking to halt litigation against Bluescape and our directors. On April 19, 2018, the Court entered a stipulation and agreed order pursuant to which, among other things: (a) Enterprise withdrew its motion to lift the stay, dismissed its claims against our directors, and agreed not to commence litigation against Bluescape (although discovery could commence) until its claims against us had been resolved; and (b) we agreed to object to any proofs of claim filed by Enterprise or Acadian in the bankruptcy cases by July 20, 2018.

On April 23, 2018, Enterprise and Acadian filed proofs of claim asserting claims against EXCO and Raider. On July 20, 2018, we filed an objection to all proofs of claim filed by Enterprise and Acadian (“Enterprise Claims Objection”), and on October 22, 2018, we filed a motion seeking summary judgment in our favor. On October 5, 2018, Enterprise filed a response to the Enterprise Claims Objection and a motion seeking the Court’s abstention therefrom (“Enterprise Abstention Motion”). On October 29, 2018, the Debtors and Bluescape each filed an objection to the Enterprise Abstention Motion. On November 14, 2018, the Enterprise Claims Objection (and related summary judgment motion) and Enterprise Abstention Motion were abated by agreement. If the abatement is lifted, litigation between us and Enterprise/Acadian could recommence in either the state court, the Court, or both.

On November 13, 2018, EXCO and Bluescape executed an agreement with EPD to settle the aforementioned litigation and claims against the Debtors ("EPD Settlement Agreement"). Per the terms of the EPD Settlement Agreement:

The proofs of claim filed by EPD in the Chapter 11 Cases shall be settled for an allowed general unsecured claim of $10.0 million. These claims primarily include costs related to the rejection of a natural gas sales agreement and natural gas transportation agreement in the North Louisiana region. On the effective date of a plan of reorganization, Bluescape shall be required to purchase the claim from Enterprise for $5.0 million;
The Debtors shall pay Enterprise: (i) $6.25 million on the effective date of a plan of reorganization, and (ii) $6.25 million on September 1, 2019; and
Upon completion of the payments from the Debtors and Bluescape to EPD, each party shall provide releases and take all actions to dismiss the aforementioned litigation.

The EPD Settlement Agreement will not be effective until it is approved by the Court. Furthermore, the EPD Settlement Agreement will be terminated if the effective date of a plan of reorganization does not occur prior to July 1, 2019. We filed a motion with the Court to approve the EPD Settlement Agreement on March 13, 2019 and the hearing is scheduled for April 11, 2019.


45



Chesapeake natural gas sales contract litigation

On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against Chesapeake Energy Marketing, LLC ("CEML") in Dallas County, Texas, Case No. DC-17-06672, in the 14th District Court of Dallas County, Texas, for allegedly wrongfully terminating a long-term sales contract with Raider. We are asserting 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, Chesapeake filed to remove the lawsuit to the United States District Court Northern District of Texas. We subsequently joined Chesapeake Energy Corporation ("CEC"). CEC has filed a motion to dismiss for lack of personal jurisdiction, and the motion remains pending. See further discussion of the impact of the wrongful termination of the contract by CEML on our ability to divest certain assets in the South Texas region in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements.

On May 24, 2018, CEML filed a motion seeking relief from the automatic stay to pursue counterclaims against us in the district court litigation. On July 23, 2018, the Court entered an order approving a joint stipulation and agreed order lifting the automatic stay to for the limited purpose of allowing CEML to assert any counterclaims or affirmative defenses in the litigation.

On February 21, 2019, EXCO executed an agreement with CEC and CEML to settle the aforementioned litigation, claims against the Debtors, and other matters ("Chesapeake Settlement Agreement"). Per the terms of the Chesapeake Settlement Agreement:

All claims filed by CEC and CEML in the Chapter 11 Cases shall be deemed disallowed and expunged. These claims primarily include costs related to the rejection of a marketing agreement in the North Louisiana region and pre-petition costs related to sales of natural gas in the South Texas region;
EXCO agreed to release CEC and CEML from pre-petition litigation including the wrongful termination of a natural gas sales contract in South Texas and improper charges for post-production costs in North Louisiana; and
EXCO will assume certain sales contracts with CEML and joint operating agreements with CEC.

The Chesapeake Settlement Agreement will not be effective until it is approved by the Court. We filed a motion with the Court to approve the Chesapeake Settlement Agreement on February 25, 2019 and the hearing is scheduled for March 20, 2019.

Shell natural gas sales contract litigation

On January 26, 2018, we initiated an adversary proceeding against Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, under Case No. 18-30155 in the bankruptcy proceeding. This lawsuit was originally filed in Harris County District Court on December 26, 2017 and subsequently non-suited after the filing of the bankruptcy petitions. We brought suit due to Shell Energy’s withholding 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. On March 23, 2018, the adversary proceeding was dismissed. The issues between Shell Energy and us related to the unpaid revenues remain outstanding.

In addition, we had withheld $28.5 million in revenues owed to Shell as a result of the dispute with Shell Energy. On October 1, 2018, the Court approved our settlement with Shell ("Shell Settlement Agreement"), pursuant to which:

EXCO will pay a total of $22.5 million to Shell, including $9.0 million within 15 days following the approval of the settlement agreement by the Court, $9.0 million within 45 days following the approval of the Court, and the remaining $4.5 million on or before the effective date of the plan of reorganization. Per the terms of the Shell Settlement Agreement, we paid Shell $18.0 million during the fourth quarter of 2018. Upon payment in full of the remaining amount, Shell shall release EXCO from any further liability related to the withheld revenues;
EXCO will commence the completion of four wells that were previously drilled in North Louisiana no later than November 15, 2018, and subsequently commence the completion of three additional wells that were previously drilled in North Louisiana. Per the terms of the Shell Settlement Agreement, we commenced completion on each of these wells during the fourth quarter of 2018 and first quarter of 2019;
EXCO shall assume the joint development agreement with Shell for the East Texas/ North Louisiana joint venture as part of the bankruptcy proceedings and any defaults occurring thereunder are deemed to be satisfied; and
Shell shall not challenge EXCO’s right to serve as operator under the joint development agreement for the East Texas/ North Louisiana joint venture for the remaining term through January 1, 2020, subject to certain exceptions.

The settlement agreement does not prevent us from asserting any claim, cross-claim, defense, or other cause of action against Shell Energy, nor does the settlement agreement prevent Shell Energy from asserting any claim, cross-claim, defense, or

46



other cause of action against us. Furthermore, the settlement agreement provides that it shall not affect any proof of claim that Shell Energy filed in the Chapter 11 Cases. On March 7, 2018, the Court approved the rejection of certain natural gas sales agreements with Shell’s affiliate, Shell Energy, and we recorded a liability of $41.5 million in “Liabilities subject to compromise” related to our current estimate of the allowed claim. The receivable for sales of oil and natural gas to Shell Energy in November and December 2017 and the estimate of the allowed claim for the rejection of the natural gas sales agreement with Shell Energy were presented as a net amount of $8.1 million in "Liabilities subject to compromise" as of December 31, 2018.

Azure minimum volume commitment litigation

On March 1, 2018, we filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018.  The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP (“EOC”) and Raider commenced an adversary proceeding against Azure under Case No. 18-03096 in the bankruptcy proceedings.  We initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties.  Various dispositive motions were filed, which were heard by the Court on August 9, 2018. In addition, on April 11, 2018, Azure filed a motion to compel payment of an administrative expense claim for payment of certain disputed compression fees, and on April 13, 2018 filed proofs of claims on account of the gathering and minimum volume commitment agreements. We objected to Azure’s proofs of claim and filed a motion to estimate the claims against EOC at $0.

On November 19, 2018, the Court approved our settlement with Azure ("Azure Settlement Agreement"), pursuant to which:

EXCO agreed to pay Azure $15.0 million and transfer equity interests held in Azure (~3.35%) on the effective date of EXCO’s plan of reorganization; and
EXCO will assume the base gathering agreement with Azure and cure any associated pre-petition amounts associated with the agreement on or before February 28, 2019.

Upon completion of the aforementioned criteria, Azure’s claims related to the base gathering agreement and minimum volume commitment will be deemed to be satisfied. On March 1, 2019, we paid $6.4 million of pre-petition costs for gathering services under the base gathering agreement. The remaining payment and transfer of equity interests are expected to be paid on the effective date of EXCO's plan of reorganization.

Natural gas flaring application

In January 2018, we commenced the flaring of natural gas produced in our South Texas region pursuant to temporary flare permits. In May 2018, we went before the Texas Railroad Commission at a hearing regarding a requested extension of the Flaring Application for up to two-years. We expect that a final ruling by the Texas Railroad Commission on the Flaring Application will be issued in early 2019.

Item 4.
Mine Safety Disclosures

Not applicable.


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PART II

Item 5.
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market information for our common shares

Our common shares have been quoted over-the-counter under the symbol "XCOOQ" since December 27, 2017. Prior to that time, our common shares were traded on the NYSE.

The following table sets forth for the periods indicated, the highest and lowest sales price for our common shares, as reported on the NYSE for the periods through December 22, 2017, and the quarterly high and low bid quotations for our common shares as reported over-the-counter for the period beginning December 27, 2017:

 
 
Price per share
 
 
High
 
Low
2018:
 
 
 
 
First Quarter
 
$
0.74

 
$
0.19

Second Quarter
 
0.39

 
0.06

Third Quarter
 
0.16

 
0.05

Fourth Quarter
 
0.14

 
0.02

 
 
 
 
 
2017:
 
 
 
 
First Quarter
 
$
14.70

 
$
7.05

Second Quarter
 
9.90

 
2.65

Third Quarter
 
2.81

 
1.00

Fourth Quarter
 
1.72

 
0.19


Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were 60 holders of record of our common shares on December 31, 2018 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders and holders of restricted shares).

Item 6.
Selected Financial Data

The information required herein has been omitted due to the relief from disclosure afforded to smaller reporting companies under Regulation S-K and Article 8 of Regulation S-X.


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Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management's discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following management's discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Overview and history
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. Our primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and acquisition opportunities.
Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and adding reserves through leasing and undeveloped acreage acquisition opportunities. Our financial condition has been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts.
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 Debtors have filed a motion with the Court seeking joint administration of their Chapter 11 cases 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.

On January 22, 2018, we closed the DIP Credit Agreement, which includes an initial borrowing base of $250.0 million. The proceeds from the DIP Facilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. On January 15, 2019, we entered into an amendment to the DIP Credit Agreement to extend the maturity date from January 22, 2019 to May 22, 2019.

On October 1, 2018, the Debtors filed the October 2018 Plan and related Disclosure Statement with the Court. On November 5, 2018, the Court authorized us to solicit acceptances of the October 2018 Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the October 2018 Plan. Simultaneous with the solicitation process, we initiated a marketing process for the issuance of a new revolving credit facility and a new second lien debt instrument. During the course of the marketing process, oil prices experienced a significant decline and overall market conditions worsened. As a result, we were not able to obtain the exit financing required to consummate the October 2018 Plan. On February 15, 2019, the Court approved a motion to extend the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019. On March 8, 2019, the Debtors filed the March 2019 Plan and related Disclosure Statement with the Court. The March 2019 Plan provides for either a reorganization of the Debtors as a going concern or an All Asset Sale. We have not received consents from any creditors in support of the March 2019 Plan.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to risks and uncertainties associated with the Chapter 11 Cases. As a result of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this annual report on Form 10-K may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases. See further discussion of the impact of the bankruptcy proceedings as part of “Note 1. Organization and basis of presentation” in the Notes to our Consolidated Financial Statements.


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Impact on our indebtedness

The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes, and 2022 Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. As of December 31, 2018, the carrying value for each of our debt instruments approximates the principal amount. The corresponding expense associated with the adjustments was recorded as “Reorganization items, net” on our Consolidated Statement of Operations for the year ended December 31, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on 1.75 Lien Term Loans, senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), 2018 Notes and 2022 Notes through the Petition Date, with no interest accrued subsequent to the filings. As a result, we expect our interest expense to decrease in the future.

Rejection of executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Company or the applicable Filing Subsidiaries for damages caused by such rejection. Our estimate of allowable claims related to the executory contracts and unexpired leases approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Consolidated Balance Sheet as of December 31, 2018 and the corresponding expense was recorded as “Reorganization items, net” in our Consolidated Statement of Operations for year ended December 31, 2018.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. On November 19, 2018, the Court approved an agreement entered into by EXCO and Azure to settle any claims related to a minimum volume commitment for gathering services in the East Texas and North Louisiana regions. We expect our realized natural gas price differentials and gathering and transportation expenses to improve in the future as a result of the rejection and settlement of these contracts.

On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022. We expect our rent expense included within general and administrative expenses to decrease in the future as a result of the rejection of this contract. See further discussion of the impact of the rejection and settlement of executory contracts as part of “Note 1. Organization and basis of presentation” in the Notes to our Consolidated Financial Statements.

Appalachia JV Settlement

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 our joint venture in Appalachia, including entities that own interests in oil and natural gas properties, an entity that operates the wells in the joint venture in Appalachia (“OPCO”) and an entity that owns and operates midstream assets in the Appalachia region (“Appalachia Midstream”). As a result, the Appalachia JV Settlement increased our production, revenues and expenses in the Appalachia region. Also, the Appalachia JV Settlement decreased our recoveries of general and administrative expenses related to the joint venture in Appalachia. See further discussion of this settlement as part of “Note 3. Acquisitions, divestitures and other significant events” in the Notes to our Consolidated Financial Statements.


50



Critical accounting estimates

The process of preparing financial statements in conformity with GAAP requires us to make estimates and assumptions to determine reported amounts of certain assets, liabilities, revenues, expenses and related disclosures. We have identified the most critical accounting policies used in the preparation of our Consolidated Financial Statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our estimates of Proved Reserves, derivative financial instruments, business combinations, equity-based compensation, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and income taxes.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP. For a more complete discussion of our accounting policies see "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated Financial Statements.

Estimates of Proved Reserves

The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

the quality and quantity of available data;
the interpretation of this data;
the accuracy of various mandated economic assumptions; and
the technical qualifications, experience and judgment of the persons preparing the estimates.
 
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our shale properties including reservoir characteristics and performance are subject to further refinement as additional production history is accumulated.

You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with the SEC's requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in the SEC's Release No. 33-8995 Modernization of Oil and Gas Reporting. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates or cost of capital.

Proved Reserve quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.

Business combinations

When we acquire assets that qualify as a business, we use FASB ASC 805-10, Business Combinations ("ASC 805-10") to record our acquisitions of oil and natural gas properties or entities. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.

Derivative financial instruments

We have historically used derivative financial instruments to manage price fluctuations, protect our investments and achieve a more predictable cash flow. The estimates of the fair values of our derivative financial instruments require judgment. The fair value of our derivative financial instruments is determined by quoted futures prices, utilization of the credit-adjusted risk-free rate curves and the implied rates of volatility. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value

51



in earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Our ability to enter into commodity derivative contracts is limited during the Chapter 11 Cases, see further discussion in "Note 4. Derivative financial instruments" in the Notes to our Consolidated Financial Statements.

On March 15, 2017, we issued warrants to investors in connection with the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans in March 2017. The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815, Derivatives and Hedging, ("ASC 815"), and required to be classified as liabilities due to the types of anti-dilution adjustments. As a pre-petition obligation that may be impacted by the Chapter 11 process, we have classified the 2017 Warrants as “Liabilities subject to compromise" on the Consolidated Balance Sheet as of December 31, 2018. The liability attributable to the 2017 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 increase or decrease in fair value of the 2017 Warrants is recognized in earnings. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. The 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise, cancellation or expiration.

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"). Our equity-based compensation for 2017 includes compensation expense for warrants issued to Energy Strategic Advisory Services LLC (“ESAS”), a subsidiary of Bluescape, which we accounted for in accordance with FASB ASC 505-50, Equity-Based Payments to Non-Employees ("ASC 505-50"). The warrants were forfeited and canceled pursuant to an agreement with ESAS entered into on November 9, 2017.

ASC 718 requires share-based compensation to employees to be recognized in our Consolidated Statements of Operations based on their estimated fair values. Estimating the grant date fair value of our share-based compensation requires management to make assumptions and to apply judgment in estimating the fair value. These assumptions and judgments include estimating the volatility of our share price, dividend yields, expected term, forfeiture rates and other company-specific inputs. ASC 505-50 requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded in our Consolidated Statements of Operations. The fair value of the warrants was dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group.

Changes in these assumptions could materially affect the estimate of the fair value. If actual results are not consistent with the assumptions used, the equity-based compensation expense reported in our financial statements may not be representative of the actual economic impact of the equity-based compensation.

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 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.

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, which 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.

52




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 amortization rate and/or 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 is computed using the simple average spot price for the trailing 12 month period using the first day of each month. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. 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.

Goodwill

In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other, goodwill shall not be amortized, but is tested for impairment at least annually, or more frequently as impairment indicators arise. Impairment tests involve the use of estimates related to the fair market value of the business operations with which goodwill is associated. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations.

As of December 31, 2018, we utilized a discounted cash flow model to value our business and corroborated the results of the valuation model through a comparison to our enterprise value that is calculated as the combined market capitalization of our equity plus the fair value of our debt. The discounted cash flow model used in the income approach requires us to make various judgmental assumptions about future production, revenues, operating and capital expenditures, discount rates and other inputs which are based on our budgets, business plans, economic projections and anticipated future cash flows. Due to the changing market conditions, it is possible that inputs and assumptions used in the valuation may change in the future, which could materially affect the estimate of the fair value of our business.

Revenue recognition and natural gas imbalances

We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Historically, these differences have been immaterial. Natural gas imbalances at December 31, 2018 were 0.7 Bcf and were reflected as a reduction to our Proved Reserves. Natural gas imbalances at December 31, 2017 were not significant.

Asset retirement obligations

We follow FASB ASC 410-20, Asset Retirement Obligations ("ASC 410-20") to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Our calculation of asset retirement obligations uses numerous assumptions and judgments,

53



including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Income taxes

Income taxes are accounted for in accordance with FASB ASC 740, Income Taxes. Deferred taxes are recorded to reflect the tax benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. We assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Examples of positive and negative evidence include historical taxable income or losses, forecasted income or losses, the estimated timing of the reversals of existing temporary differences as well as prudent and feasible tax planning strategies. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of December 31, 2018, we continued to have a full valuation allowance against our net deferred tax assets. A significant amount of judgment is also required in determining the amount of unrecognized tax benefit to record for uncertain tax positions. We consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of unrecognized tax benefit. We currently do not have any uncertain tax positions recorded as of December 31, 2018.


54



Our results of operations

A summary of key financial data for the years ended December 31, 2018 and 2017 related to our results of operations is presented below:
 
 
Year Ended December 31,
 
Year to year Change
(dollars in thousands, except per unit prices)
 
2018
 
2017
 
Production:
 
 
 
 
 
 
Oil (Mbbls)
 
1,357

 
1,158

 
199

Natural gas (Mmcf)
 
98,779

 
80,136

 
18,643

Total production (Mmcfe) (1)
 
106,921

 
87,084

 
19,837

Average daily production (Mmcfe)
 
293

 
239

 
54

Revenues before commodity derivative financial instrument activities:
Oil
 
$
90,614

 
$
57,693

 
$
32,921

Natural gas
 
281,977

 
201,137

 
80,840

Total oil and natural gas revenues
 
372,591

 
258,830

 
113,761

Purchased natural gas and marketing
 
21,435

 
24,816

 
(3,381
)
Total revenues
 
$
394,026

 
$
283,646

 
$
110,380

Commodity derivative financial instruments:
Gain (loss) on derivative financial instruments - commodity derivatives
 
$
(615
)
 
$
24,732

 
$
(25,347
)
Average sales price (before cash settlements of commodity derivative financial instruments):
Oil (per Bbl)
 
$
66.78

 
$
49.82

 
$
16.96

Natural gas (per Mcf)
 
2.85

 
2.51

 
0.34

Natural gas equivalent (per Mcfe)
 
3.48

 
2.97

 
0.51

Costs and expenses:
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
42,149

 
$
35,011

 
$
7,138

Production and ad valorem taxes
 
15,260

 
13,131

 
2,129

Gathering and transportation
 
76,175

 
111,427

 
(35,252
)
Purchased natural gas
 
16,387

 
23,400

 
(7,013
)
Depletion
 
78,981

 
50,066

 
28,915

Depreciation and amortization
 
1,308

 
974

 
334

General and administrative (2)
 
27,850

 
30,165

 
(2,315
)
Interest expense, net
 
33,917

 
108,175

 
(74,258
)
Costs and expenses (per Mcfe):
 
 
 
 
 
 
Oil and natural gas operating costs
 
$
0.39

 
$
0.40

 
$
(0.01
)
Production and ad valorem taxes
 
0.14

 
0.15

 
(0.01
)
Gathering and transportation
 
0.71

 
1.28

 
(0.57
)
Depletion
 
0.74

 
0.57

 
0.17

Depreciation and amortization
 
0.01

 
0.01

 

Net income (loss) (3)
 
$
(182,697
)
 
$
24,362

 
$
(207,059
)

(1)
Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.
(2)
Equity-based compensation included in general and administrative expense was expense of $2.1 million and income of $11.4 million for the years ended December 31, 2018 and 2017, respectively.
(3)
Net loss for the for the year ended December 31, 2018 includes the effects of the gain recognized from the Appalachia JV Settlement of $119.2 million and net costs associated with the Chapter 11 Cases of $409.3 million. Net income for the year ended December 31, 2017 includes the effect of the $159.2 million gain recognized due to the change in fair value of our common share warrants resulting from a decrease in our share price during the period.


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The following is a discussion of our financial condition and results of operations for the years ended December 31, 2018 and 2017. The comparability of our results of operations for the years ended December 31, 2018 and 2017 was affected by:

changes in general and administrative expenses as a result of legal and professional fees incurred in connection with the restructuring process;
rejection of certain executory contracts as part of the Chapter 11 Cases related to the sale, marketing and transportation of natural gas in the North Louisiana region, and the office lease for our corporate headquarters;
impact of the Chapter 11 Cases on our indebtedness, including the adjustments to the carrying value as well as the accrual of interest during the pendency of the bankruptcy proceedings;
gains from the settlement of litigation with our Appalachian joint venture partner during 2018, as well as increased production, revenues and operating expenses attributable to the acquired interests;
fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;
mark-to-market gains and losses from our derivative financial instruments, including gains on the 2017 Warrants due to a decrease in EXCO’s share price;
changes in proved reserves and production volumes and their impact on depletion; and
the impact of development activities on our oil and natural gas production.

Oil and natural gas production, revenues and prices

The following table presents our production, revenue and average sales prices for the years ended December 31, 2018 and 2017:
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2018
 
2017
 
Year to year change
(dollars in thousands, except per unit rate)
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
 
Production (Mmcfe)
 
Revenue
 
$/Mcfe
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
70,104

 
$
206,396

 
$
2.94

 
53,373

 
$
138,653

 
$
2.60

 
16,731

 
$
67,743

 
$
0.34

East Texas
 
10,828

 
31,070

 
2.87

 
16,106

 
45,026

 
2.80

 
(5,278
)
 
(13,956
)
 
0.07

South Texas
 
8,160

 
90,308

 
11.07

 
7,742

 
54,084

 
6.99

 
418

 
36,224

 
4.08

Appalachia and other
 
17,829

 
44,817

 
2.51

 
9,863

 
21,067

 
2.14

 
7,966

 
23,750

 
0.37

Total
 
106,921

 
$
372,591

 
$
3.48

 
87,084

 
$
258,830

 
$
2.97

 
19,837

 
$
113,761

 
$
0.51


Production for the year ended December 31, 2018 increased by 19.8 Bcfe, or 23%, as compared to the same period in 2017. Significant components of the changes in production were a result of:

Increased production of 16.7 Bcfe for the year ended December 31, 2018 in the North Louisiana region, primarily due to 11 gross (6.7 net) operated wells turned-to-sales in the first quarter of 2018 and 8 gross (4.9 net) operated wells turned-to-sales in the fourth quarter of 2017.
Decreased production of 5.3 Bcfe for the year ended December 31, 2018 in the East Texas region, primarily due to natural production declines as we have not turned an operated well to sales in the region since the first quarter of 2016.
Increased production of 0.4 Bcfe for the year ended December 31, 2018 in the South Texas region. We turned-to-sales 9 gross (8.6 net) operated wells in the first half of 2018 and an additional 7 gross (4.3 net) wells in the second half of 2018. We expect continued increases in production in 2019 due to additional wells turned-to-sales in mid to late 2019. Prior to the first quarter of 2018, the most recent operated well turned-to-sales in this region was in the fourth quarter of 2015.
Increased production of 8.0 Bcfe for the year ended December 31, 2018 in the Appalachia region, primarily due to the acquisition of additional interests in the Appalachia JV Settlement and 1 gross (0.9 net) operated well turned-to-sales in the first quarter of 2018. The last well that turned to sales in the Appalachia region prior to the first quarter of 2018 was in late 2015.

Oil and natural gas revenues for the year ended December 31, 2018 increased by $113.8 million, or 44%, as compared to the same period in 2017. The increase in revenues was primarily the result of an increase in oil and natural gas prices and an increase in production. Our average natural gas sales price increased 14% to $2.85 per Mcf for the year ended December 31, 2018 from $2.51 per Mcf for the year ended December 31, 2017, primarily due to improved natural gas price differentials as a

56



result of the rejection of certain executory contracts for the sale and marketing of natural gas in the North Louisiana region. Our average sales price of oil per Bbl increased 34% to $66.78 per Bbl for the year ended December 31, 2018 from $49.82 per Bbl for the year ended December 31, 2017, primarily due to higher market prices.

Purchased natural gas and marketing revenues

Purchased natural gas and marketing revenues include revenues we receive as a result of selling natural gas purchased from third parties and marketing fees we receive from third parties. Purchased natural gas and marketing revenues for the year ended December 31, 2018 decreased by $3.4 million, or 14%, as compared to the same period in 2017. The decrease for the year ended December 31, 2018 was primarily due to lower marketing fees charged to third parties and lower volumes purchased. The decrease in marketing fees charged to third parties was primarily due to an increase in our average working interests in production from operated wells compared to the same period in prior year.

Oil and natural gas operating costs

The following tables present our oil and natural gas operating costs for the years ended December 31, 2018 and 2017:
 
 
Year Ended December 31,
 
 
 
 
 
 
 
 
2018
 
2017
 
Year to year change
(in thousands)
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
 
Lease operating expenses
 
Workovers and other
 
Total
Producing region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Louisiana
 
$
17,939

 
$
2,091

 
$
20,030

 
$
14,055

 
$
3,130

 
$
17,185

 
$
3,884

 
$
(1,039
)
 
$
2,845

East Texas
 
3,655

 
1,696

 
5,351

 
4,585

 
828

 
5,413

 
(930
)
 
868

 
(62
)
South Texas
 
12,422

 
90

 
12,512

 
10,677

 
4

 
10,681

 
1,745

 
86

 
1,831

Appalachia and other
 
3,585

 
671

 
4,256

 
1,694

 
38