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 |
o | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
FOR THE TRANSITION PERIOD FROM __________TO __________ |
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) |
Large accelerated filer o | Accelerated filer o | |
Non-accelerated filer þ | Smaller reporting company þ | |
Emerging growth company o |
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. |
• | 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. |
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. |
• | 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. |
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. |
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 |
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 |
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 |
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. |
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. |
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 |
• | 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. |
• | 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. |
• | 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; |
• | 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. |
Item 1A. | Risk Factors |
• | 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. |
• | 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; |
• | 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. |
• | 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. |
• | 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. |
• | 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. |
• | 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). |
• | 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. |
• | 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. |
• | 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. |
• | 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. |
Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
Location | Approximate square footage | Approximate remaining monthly payment | Expiration | ||||||
Dallas, Texas | 48,000 | $ | 95,000 | December 31, 2022 |
Item 3. | Legal Proceedings |
• | 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. |
• | 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. |
• | 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. |
• | 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. |
Item 4. | Mine Safety Disclosures |
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 |
• | 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. |
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. |
• | 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. |
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 |
• | 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. |
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 | 1,732 | 1,891 | 633 | 2,524 | |||||||||||||||||||||||||||
Total | $ | 37,601 | $ | 4,548 | $ | 42,149 | $ | 31,011 | $ | 4,000 | $ | 35,011 | $ | 6,590 | $ | 548 | $ | 7,138 | ||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
2018 | 2017 | Year to year change | ||||||||||||||||||||||||||||||||||
(per Mcfe) | 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 | $ | 0.26 | $ | 0.03 | $ | 0.29 | $ | 0.26 | $ | 0.06 | $ | 0.32 | $ | — | $ | (0.03 | ) | $ | (0.03 | ) | ||||||||||||||||
East Texas | 0.34 | 0.16 | 0.50 | 0.28 | 0.05 | 0.33 | 0.06 | 0.11 | 0.17 | |||||||||||||||||||||||||||
South Texas | 1.52 | 0.01 | 1.53 | 1.38 | — | 1.38 | 0.14 | 0.01 | 0.15 | |||||||||||||||||||||||||||
Appalachia and other | 0.20 | 0.04 | 0.24 | 0.17 | — | 0.17 | 0.03 | 0.04 | 0.07 | |||||||||||||||||||||||||||
Total | $ | 0.35 | $ | 0.04 | $ | 0.39 | $ | 0.36 | $ | 0.04 | $ | 0.40 | $ | (0.01 | ) | $ | — | $ | (0.01 | ) |
Year Ended December 31, | ||||||||||||||||||||||
2018 | 2017 | |||||||||||||||||||||
(in thousands, except per unit rate) | Production and ad valorem taxes | % of revenue | Taxes $/Mcfe | Production and ad valorem taxes | % of revenue | Taxes $/Mcfe | ||||||||||||||||
Producing region: | ||||||||||||||||||||||
North Louisiana | $ | 6,609 | 3.2 | % | $ | 0.09 | $ | 6,936 | 5.0 | % | $ | 0.13 | ||||||||||
East Texas | 635 | 2.0 | % | 0.06 | 1,291 | 2.9 | % | 0.08 | ||||||||||||||
South Texas | 6,008 | 6.7 | % | 0.74 | 4,300 | 8.0 | % | 0.56 | ||||||||||||||
Appalachia and other | 2,008 | 4.5 | % | 0.11 | 604 | 2.9 | % | 0.06 | ||||||||||||||
Total | $ | 15,260 | 4.1 | % | $ | 0.14 | $ | 13,131 | 5.1 | % | $ | 0.15 |
Year Ended December 31, | ||||||||||||
(in thousands) | 2018 | 2017 | Year to year change | |||||||||
General and administrative expenses: | ||||||||||||
Gross general and administrative expenses | $ | 47,072 | $ | 65,484 | $ | (18,412 | ) | |||||
Technical services and service agreement charges | (4,284 | ) | (6,386 | ) | 2,102 | |||||||
Operator overhead reimbursements | (14,060 | ) | (14,585 | ) | 525 | |||||||
Capitalized salaries | (2,931 | ) | (2,918 | ) | (13 | ) | ||||||
General and administrative expenses, excluding equity-based compensation | 25,797 | 41,595 | (15,798 | ) | ||||||||
Gross equity-based compensation | 2,400 | (10,430 | ) | 12,830 | ||||||||
Capitalized equity-based compensation | (347 | ) | (1,000 | ) | 653 | |||||||
General and administrative expenses | $ | 27,850 | $ | 30,165 | $ | (2,315 | ) |
• | Higher equity-based compensation of $13.5 million for the year ended December 31, 2018, primarily due to income in the prior year of $14.5 million related to a significant decline in the fair value of the warrants issued to ESAS. This was partially offset by a decrease in equity-based compensation of $1.7 million for the year ended December 31, 2018 due to the discontinuation of grants of share-based compensation to employees and lower employee headcount. |
• | Increased personnel costs of $2.3 million for year ended December 31, 2018. The increase was primarily due to higher cash-based bonus expense during the current year, partially offset by variable costs associated with lower headcount. The increase in bonus expense was due to the adoption of new cash-based retention and incentive plans in connection with our restructuring activities. The cash-based retention and incentive plans are intended to replace grants under the discontinued equity-based incentive plans. As a result, cash-based personnel costs increased and equity-based compensation expense decreased. |
• | Decreased consulting and contract labor costs $2.9 million for the year ended December 31, 2018 primarily due to the suspension of the services and investment agreement with ESAS that was effective November 9, 2017. |
• | Decreased legal and professional fees of $14.7 million for the year ended December 31, 2018. Our legal and professional fees during 2017 primarily consisted of legal, financial and restructuring advisors engaged to evaluate strategic alternatives. Any legal and professional fees related to the Chapter 11 Cases incurred subsequent to the Petition Date are classified as “Reorganization items, net” on the Consolidated Statement of Operations. |
• | Decreased overhead reimbursement, technical services and service agreement charges of $2.6 million for the year ended December 31, 2018. The decreases are primarily a result of lower recoveries from third parties due to the acquisition of our joint venture partner’s interests in the Appalachia JV Settlement. |
• | Decreased various other gross general and administrative expenses of $3.1 million for the year ended December 31, 2018. These decreases reflect our continued efforts to reduce our general and administrative costs. |
Year Ended December 31, | ||||||||||||
Average realized pricing: | 2018 | 2017 | Year to year change | |||||||||
Natural gas (per Mcf): | ||||||||||||
Net price, excluding derivatives | $ | 2.85 | $ | 2.51 | $ | 0.34 | ||||||
Cash receipts (payments) on derivatives | 0.01 | (0.05 | ) | 0.06 | ||||||||
Net price, including derivatives | $ | 2.86 | $ | 2.46 | $ | 0.40 | ||||||
Oil (per Bbl): | ||||||||||||
Net price, excluding derivatives | $ | 66.78 | $ | 49.82 | $ | 16.96 | ||||||
Cash receipts (payments) on derivatives | — | (0.15 | ) | 0.15 | ||||||||
Net price, including derivatives | $ | 66.78 | $ | 49.67 | $ | 17.11 | ||||||
Natural gas equivalent (per Mcfe): | ||||||||||||
Net price, excluding derivatives | $ | 3.48 | $ | 2.97 | $ | 0.51 | ||||||
Cash receipts (payments) on derivatives | 0.01 | (0.05 | ) | 0.06 | ||||||||
Net price, including derivatives | $ | 3.49 | $ | 2.92 | $ | 0.57 |
Year Ended December 31, | ||||||||||||
(in thousands) | 2018 | 2017 | Year to year change | |||||||||
Income tax (benefit) expense: | ||||||||||||
Current income tax (benefit) expense | $ | — | $ | (1,420 | ) | $ | 1,420 | |||||
Deferred income tax (benefit) expense | (4,518 | ) | 1,716 | (6,234 | ) | |||||||
Total income tax (benefit) expense | $ | (4,518 | ) | $ | 296 | $ | (4,814 | ) |
• | 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; |
• | decisions from the Court related to requirements to pay interest on certain debt instruments during the bankruptcy process; |
• | our ability to maintain compliance with debt covenants under the DIP Credit Agreement; |
• | our ability to fund, finance or repay indebtedness, including our ability to restructure our indebtedness during the Chapter 11 Cases; |
• | limitations on our ability to incur certain types of indebtedness in accordance with our debt agreements; |
• | requirements to provide certain vendors and other parties with letters of credit or cash deposits as a result of our credit quality, which reduce the amount of available borrowings under the DIP Credit Agreement; |
• | costs related to the settlement of pre-petition claims; |
• | our ability to obtain exit financing on favorable terms in order to consummate a plan of reorganization prior to the maturity of the DIP Credit Agreement on May 22, 2019, or our ability to obtain the waivers or consents required from the DIP Lenders to extend the DIP Credit Agreement; |
• | the level of planned drilling activities; |
• | the results of our ongoing drilling programs; |
• | potential acquisitions and/or dispositions of oil and natural gas properties or other assets; |
• | the integration of acquisitions of oil and natural gas properties or other assets; |
• | our ability to effectively manage operating, general and administrative expenses and capital expenditure programs, specifically related to pricing pressures from key vendors utilized in our drilling, completion and operating activities; |
• | reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production from reductions in our drilling and development activities; |
• | our ability to mitigate commodity price volatility with commodity derivative financial instruments; and |
• | the potential outcome of litigation. |
(in thousands) | December 31, 2018 | |||
DIP Credit Agreement | $ | 156,406 | ||
1.5 Lien Notes | 316,958 | |||
1.75 Lien Term Loans | 708,926 | |||
Second Lien Term Loans | 17,246 | |||
2018 Notes | 131,576 | |||
2022 Notes | 70,169 | |||
Total debt | $ | 1,401,281 | ||
Net debt | $ | 1,338,691 | ||
Borrowing base | $ | 250,000 | ||
Unused borrowing base (1) | $ | 81,600 | ||
Cash (2) | $ | 62,590 | ||
Unused borrowing base plus cash | $ | 144,190 |
(1) | Net of $12.0 million in letters of credit at December 31, 2018. |
(2) | Includes restricted cash of $16.0 million at December 31, 2018. |
• | our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million (“Minimum Liquidity Test”); and |
• | aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the administrative agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the administrative agent of the DIP Credit Agreement. |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Net cash provided by operating activities | $ | 133,996 | $ | 54,411 | ||||
Net cash used in investing activities | (150,217 | ) | (178,430 | ) | ||||
Net cash provided by financing activities | 23,943 | 158,669 | ||||||
Net increase in cash | $ | 7,722 | $ | 34,650 |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Capital expenditures: | ||||||||
Lease purchases and seismic | $ | 1,177 | $ | 5,854 | ||||
Development capital expenditures | 146,834 | 147,861 | ||||||
Field operations, gathering and water pipelines | 1,208 | 220 | ||||||
Corporate and other | 7,546 | 11,483 | ||||||
Total capital expenditures excluding oil and natural gas property acquisitions | 156,765 | 165,418 | ||||||
Oil and natural gas property acquisitions (1) | — | 24,465 | ||||||
Total capital expenditures including oil and natural gas property acquisitions | $ | 156,765 | $ | 189,883 |
(1) | The fair value of the assets and liabilities acquired as a result of the Appalachia JV Settlement was $128.9 million, which includes the acquired interests in oil and gas properties and the consolidation of the net assets of OPCO and Appalachia Midstream. Per the terms of the settlement agreement, the acquisition of interests in oil and gas properties and equity investments did not require us to transfer any cash consideration. See "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements for further discussion of the Appalachia JV Settlement. |
(in thousands) | 2019 Capital Budget | |||
Lease purchases and seismic | $ | 4,000 | ||
Development capital expenditures | 136,800 | |||
Field operations, gathering and water pipelines | 6,600 | |||
Corporate and other | 4,000 | |||
Total capital expenditures | $ | 151,400 |
Item 8. | Financial Statements and Supplementary Data |
By: | /s/ Harold L. Hickey | By: | /s/ Tyler S. Farquharson | |
Title: | Chief Executive Officer and President | Title: | Vice President, Chief Financial Officer and Treasurer | |
Dallas, Texas | ||||
March 18, 2019 |
(in thousands) | December 31, 2018 | December 31, 2017 | ||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 46,541 | $ | 39,597 | ||||
Restricted cash | 16,049 | 15,271 | ||||||
Accounts receivable, net: | ||||||||
Oil and natural gas | 61,947 | 55,692 | ||||||
Joint interest | 32,089 | 30,570 | ||||||
Other | 2,050 | 1,976 | ||||||
Derivative financial instruments - commodity derivatives | — | 1,150 | ||||||
Other current assets | 11,467 | 23,574 | ||||||
Total current assets | 170,143 | 167,830 | ||||||
Equity investments | 4,732 | 14,181 | ||||||
Oil and natural gas properties (full cost accounting method): | ||||||||
Unproved oil and natural gas properties and development costs not being amortized | 155,646 | 118,652 | ||||||
Proved developed and undeveloped oil and natural gas properties | 3,332,779 | 3,107,566 | ||||||
Accumulated depletion | (2,831,293 | ) | (2,752,311 | ) | ||||
Oil and natural gas properties, net | 657,132 | 473,907 | ||||||
Other property and equipment, net and other non-current assets | 37,531 | 21,274 | ||||||
Goodwill | 163,155 | 163,155 | ||||||
Total assets | $ | 1,032,693 | $ | 840,347 | ||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 64,925 | $ | 68,277 | ||||
Revenues and royalties payable | 45,316 | 207,956 | ||||||
Accrued interest payable | 7,088 | 27,637 | ||||||
Current portion of asset retirement obligations | 600 | 600 | ||||||
Current maturities of long-term debt | 473,364 | 1,362,500 | ||||||
Total current liabilities | 591,293 | 1,666,970 | ||||||
Deferred income taxes | — | 4,518 | ||||||
Derivative financial instruments - common share warrants | — | 1,950 | ||||||
Asset retirement obligations and other long-term liabilities | 24,413 | 13,108 | ||||||
Liabilities subject to compromise | 1,443,483 | — | ||||||
Commitments and contingencies | ||||||||
Shareholders’ equity: | ||||||||
Common shares, par value $0.001, 260,000,000 shares authorized; 21,624,129 shares issued and 21,584,514 shares outstanding at December 31, 2018; 21,670,186 shares issued and 21,630,541 shares outstanding at December 31, 2017 | 22 | 22 | ||||||
Additional paid-in capital | 3,541,822 | 3,539,422 | ||||||
Accumulated deficit | (4,560,708 | ) | (4,378,011 | ) | ||||
Treasury shares, at cost; 39,645 shares at December 31, 2018 and December 31, 2017 | (7,632 | ) | (7,632 | ) | ||||
Total shareholders’ equity | (1,026,496 | ) | (846,199 | ) | ||||
Total liabilities and shareholders’ equity | $ | 1,032,693 | $ | 840,347 |
Year Ended December 31, | ||||||||
(in thousands, except per share data) | 2018 | 2017 | ||||||
Revenues: | ||||||||
Oil | $ | 90,614 | $ | 57,693 | ||||
Natural gas | 281,977 | 201,137 | ||||||
Purchased natural gas and marketing | 21,435 | 24,816 | ||||||
Total revenues | 394,026 | 283,646 | ||||||
Costs and expenses: | ||||||||
Oil and natural gas operating costs | 42,149 | 35,011 | ||||||
Production and ad valorem taxes | 15,260 | 13,131 | ||||||
Gathering and transportation | 76,175 | 111,427 | ||||||
Purchased natural gas | 16,387 | 23,400 | ||||||
Depletion, depreciation and amortization | 80,289 | 51,040 | ||||||
Accretion of liabilities | 1,997 | 874 | ||||||
General and administrative | 27,850 | 30,165 | ||||||
Gain on Appalachia JV Settlement | (119,237 | ) | — | |||||
Other operating items | (1,325 | ) | 59,154 | |||||
Total costs and expenses | 139,545 | 324,202 | ||||||
Operating income (loss) | 254,481 | (40,556 | ) | |||||
Other income (expense): | ||||||||
Interest expense, net | (33,917 | ) | (108,175 | ) | ||||
Gain (loss) on derivative financial instruments - commodity derivatives | (615 | ) | 24,732 | |||||
Gain on derivative financial instruments - common share warrants | 1,889 | 159,190 | ||||||
Loss on restructuring and extinguishment of debt | — | (6,380 | ) | |||||
Other income | 70 | 31 | ||||||
Equity income (loss) | 175 | (4,184 | ) | |||||
Reorganization items, net | (409,298 | ) | — | |||||
Total other income (expense) | (441,696 | ) | 65,214 | |||||
Income (loss) before income taxes | (187,215 | ) | 24,658 | |||||
Income tax expense (benefit) | (4,518 | ) | 296 | |||||
Net income (loss) | $ | (182,697 | ) | $ | 24,362 | |||
Earnings (loss) per common share: | ||||||||
Basic: | ||||||||
Net income (loss) | $ | (8.42 | ) | $ | 1.14 | |||
Weighted average common shares outstanding | 21,686 | 21,288 | ||||||
Diluted: | ||||||||
Net income (loss) | $ | (8.42 | ) | $ | 1.14 | |||
Weighted average common shares and common share equivalents outstanding | 21,686 | 21,288 |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Operating Activities: | ||||||||
Net income (loss) | $ | (182,697 | ) | $ | 24,362 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Deferred income tax expense (benefit) | (4,518 | ) | 1,716 | |||||
Depletion, depreciation and amortization | 80,289 | 51,040 | ||||||
Equity-based compensation | 2,053 | (11,430 | ) | |||||
Accretion of liabilities | 1,997 | 874 | ||||||
(Income) loss from equity investments | (175 | ) | 4,184 | |||||
Proceeds from equity investments | — | 4,452 | ||||||
(Gain) loss on derivative financial instruments - commodity derivatives | 615 | (24,732 | ) | |||||
Cash receipts (payments) of commodity derivative financial instruments | 535 | (4,111 | ) | |||||
Gain on derivative financial instruments - common share warrants | (1,889 | ) | (159,190 | ) | ||||
Amortization of deferred financing costs and discount on debt issuance | 4,166 | 26,960 | ||||||
Gain on Appalachia JV Settlement | (119,237 | ) | — | |||||
Non-cash and non-operating reorganization items, net | 341,342 | — | ||||||
Loss on restructuring and extinguishment of debt | — | 6,380 | ||||||
Paid in-kind interest expense | (21,078 | ) | 59,464 | |||||
Other non-operating items | — | 2,006 | ||||||
Effect of changes in: | ||||||||
Accounts receivable | (3,837 | ) | (7,160 | ) | ||||
Other current assets | 13,207 | (12,498 | ) | |||||
Accounts payable and other liabilities | 23,223 | 92,094 | ||||||
Net cash provided by operating activities | 133,996 | 54,411 | ||||||
Investing Activities: | ||||||||
Additions to oil and natural gas properties, gathering assets and equipment | (165,999 | ) | (147,016 | ) | ||||
Property acquisitions | 14,832 | (24,151 | ) | |||||
Proceeds from disposition of property and equipment | — | 350 | ||||||
Net changes in amounts due to joint ventures | — | (9,161 | ) | |||||
Other | 950 | 1,548 | ||||||
Net cash used in investing activities | (150,217 | ) | (178,430 | ) | ||||
Financing Activities: | ||||||||
Borrowings under DIP Credit Agreement | 156,406 | — | ||||||
Borrowings under EXCO Resources Credit Agreement | — | 163,401 | ||||||
Repayments under EXCO Resources Credit Agreement | (126,401 | ) | (265,592 | ) | ||||
Proceeds received from issuance of 1.5 Lien Notes, net | — | 295,530 | ||||||
Payments on Second Lien Term Loans | — | (11,602 | ) | |||||
Payments of common share dividends | — | (6 | ) | |||||
Debt financing costs and other | (6,062 | ) | (23,062 | ) | ||||
Net cash provided by financing activities | 23,943 | 158,669 | ||||||
Net increase in cash, cash equivalents and restricted cash | 7,722 | 34,650 | ||||||
Cash, cash equivalents and restricted cash at beginning of period | 54,868 | 20,218 | ||||||
Cash, cash equivalents and restricted cash at end of period | $ | 62,590 | $ | 54,868 | ||||
Supplemental Cash Flow Information: | ||||||||
Cash interest payments | $ | 35,000 | $ | 27,786 | ||||
Income tax payments | — | — | ||||||
Supplemental non-cash investing and financing activities: | ||||||||
Capitalized equity-based compensation | $ | 347 | $ | 1,000 | ||||
Capitalized interest | 3,357 | 6,440 | ||||||
Net assets acquired on Appalachia JV Settlement, excluding cash and cash equivalents | 114,028 | — |
Common shares | Treasury shares | Additional paid-in capital | Accumulated deficit | Total shareholders’ equity | ||||||||||||||||||||||
(in thousands) | Shares | Amount | Shares | Amount | ||||||||||||||||||||||
Balance at December 31, 2016 | 18,916 | $ | 19 | (40 | ) | $ | (7,632 | ) | $ | 3,538,080 | $ | (4,402,373 | ) | $ | (871,906 | ) | ||||||||||
Issuance of common shares | 2,746 | 3 | — | — | 11,395 | — | 11,398 | |||||||||||||||||||
Equity-based compensation | — | — | — | — | (10,053 | ) | — | (10,053 | ) | |||||||||||||||||
Restricted shares issued, net of cancellations | 8 | — | — | — | — | — | — | |||||||||||||||||||
Net income | — | — | — | — | — | 24,362 | 24,362 | |||||||||||||||||||
Balance at December 31, 2017 | 21,670 | $ | 22 | (40 | ) | $ | (7,632 | ) | $ | 3,539,422 | $ | (4,378,011 | ) | $ | (846,199 | ) | ||||||||||
Equity-based compensation | — | — | — | — | 2,400 | — | 2,400 | |||||||||||||||||||
Restricted shares issued, net of cancellations | (46 | ) | — | — | — | — | — | — | ||||||||||||||||||
Net loss | — | — | — | — | — | (182,697 | ) | (182,697 | ) | |||||||||||||||||
Balance at December 31, 2018 | 21,624 | $ | 22 | (40 | ) | $ | (7,632 | ) | $ | 3,541,822 | $ | (4,560,708 | ) | $ | (1,026,496 | ) |
• | EXCO Resources Credit Agreement; |
• | 1.5 Lien Notes; |
• | 1.75 Lien Term Loans; |
• | 2018 Notes; and |
• | 2022 Notes. |
• | Firm transportation agreements with Acadian Gas Pipeline System, which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025; |
• | Natural gas sales agreements with Enterprise Products Operating LLC (“Enterprise”), which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025; |
• | Firm transportation agreements with Regency Intrastate Gas Systems LLC, which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation charges through January 31, 2020; |
• | Marketing agreement with a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), which required us to allow Chesapeake to purchase natural gas from certain wells in North Louisiana through 2021; and |
• | Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020. |
• | 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. |
• | 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. |
(in thousands) | December 31, 2018 | |||
Current maturities of long-term debt | $ | 927,917 | ||
Accrued interest payable | 34,281 | |||
Accounts payable, accrued expenses and other liabilities | 95,915 | |||
Liabilities related to rejected executory contracts | 385,370 | |||
Liabilities subject to compromise | $ | 1,443,483 |
(in thousands) | Year Ended December 31, 2018 | |||
Legal and professional fees | $ | 67,790 | ||
Deferred financing costs, debt discounts and deferred reductions in carrying value | 30,509 | |||
Rejection of executory contracts | 312,182 | |||
Other | (1,183 | ) | ||
Reorganization items, net | $ | 409,298 |
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 |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Asset retirement obligations at beginning of period | $ | 12,017 | $ | 11,289 | ||||
Activity during the period: | ||||||||
Liabilities incurred during the period | — | 12 | ||||||
Revisions in estimated assumptions | (1 | ) | — | |||||
Liabilities settled during the period | (77 | ) | (175 | ) | ||||
Adjustment to liability due to acquisitions (1) | 2,319 | 17 | ||||||
Adjustment to liability due to divestitures | (7 | ) | — | |||||
Accretion of discount | 1,054 | 874 | ||||||
Asset retirement obligations at end of period | 15,305 | 12,017 | ||||||
Less current portion | 600 | 600 | ||||||
Long-term portion | $ | 14,705 | $ | 11,417 |
(1) | The increase in our asset retirement obligations during the year ended December 31, 2018 is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement. |
• | Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and Appalachia Midstream, LLC (“Appalachia Midstream”). On April 20, 2018, BG Production Company (PA), LLC legally changed its name to EXCO Production Company (PA) II, LLC and BG Production Company (WV), LLC legally changed its name to EXCO Production Company (WV) II, LLC; |
• | Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV; |
• | EXCO reconveyed its interests in certain leases, representing an interest in 364 net acres, that EXCO had previously acquired from Shell within the area of mutual interest, in exchange for consideration of $0.7 million; |
• | EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages and remedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest, the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region, except as expressly provided in the settlement; and |
• | EXCO caused the arbitration and the state court action to be dismissed with prejudice. |
(in thousands) | Amount | |||
Assets acquired: | ||||
Cash and cash equivalents | $ | 14,832 | ||
Accounts receivable, net | 6,493 | |||
Other current assets | 5,264 | |||
Unproved oil and natural gas properties | 33,542 | |||
Proved developed and undeveloped oil and natural gas properties, net | 72,548 | |||
Other assets | 18,109 | |||
Liabilities assumed: | ||||
Accounts payable and accrued liabilities | (9,718 | ) | ||
Asset retirement obligations | (2,315 | ) | ||
Other long-term liabilities | (9,895 | ) | ||
Fair value of net assets acquired | $ | 128,860 |
Year Ended December 31, | |||||||
(in thousands except for per share data) | 2018 | 2017 | |||||
Oil and natural gas revenues | $ | 398,105 | $ | 305,371 | |||
Net income (loss) (1) | (181,437 | ) | 27,971 | ||||
Basic earnings (loss) per share | $ | (8.37 | ) | $ | 1.31 | ||
Diluted earnings (loss) per share | $ | (8.37 | ) | $ | 1.31 |
(1) | The pro forma results of operations include adjustments for revenues and direct expenses related to the interests acquired as part of the Appalachia JV Settlement. Net income (loss) for the year ended December 31, 2018 includes the non-cash gains or losses associated with the fair value of net assets acquired and remeasurement of previously held interests in OPCO and Appalachia Midstream. |
(in thousands) | December 31, 2018 | December 31, 2017 | ||||||||
Current assets | Derivative financial instruments - commodity derivatives | $ | — | $ | 1,150 | |||||
Liabilities subject to compromise | Derivative financial instruments - common share warrants | (61 | ) | — | ||||||
Long-term liabilities | Derivative financial instruments - common share warrants | — | (1,950 | ) |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Gain (loss) on derivative financial instruments - commodity derivatives | $ | (615 | ) | $ | 24,732 | |||
Gain on derivative financial instruments - common share warrants | 1,889 | 159,190 |
(in thousands) | December 31, 2018 | December 31, 2017 | ||||||
DIP Credit Agreement | $ | 156,406 | $ | — | ||||
EXCO Resources Credit Agreement | — | 126,401 | ||||||
1.5 Lien Notes, net of unamortized discount | 316,958 | 176,560 | ||||||
1.75 Lien Term Loans, net of unamortized discount | 708,926 | 845,763 | ||||||
Second Lien Term Loans | 17,246 | 23,543 | ||||||
2018 Notes, net of unamortized discount | 131,576 | 131,345 | ||||||
2022 Notes | 70,169 | 70,169 | ||||||
Deferred financing costs, net | — | (11,281 | ) | |||||
Total debt, net | 1,401,281 | 1,362,500 | ||||||
Less amounts included in liabilities subject to compromise | 927,917 | — | ||||||
Current maturities of long-term debt | $ | 473,364 | $ | 1,362,500 |
(in thousands) | December 31, 2018 | |||
1.75 Lien Term Loans | $ | 28,800 | ||
Second Lien Term Loans | 701 | |||
2018 Notes | 3,289 | |||
2022 Notes | 1,491 | |||
Accrued interest payable classified as Liabilities subject to compromise | $ | 34,281 |
• | our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million; and |
• | aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the DIP Agent. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the DIP Agent. |
As of December 31, 2018 | ||||||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Liabilities: | ||||||||||||||||
Derivative financial instruments - common share warrants | $ | — | $ | 61 | $ | — | $ | 61 | ||||||||
As of December 31, 2017 | ||||||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: | ||||||||||||||||
Derivative financial instruments - commodity derivatives | $ | — | $ | 1,150 | $ | — | $ | 1,150 | ||||||||
Liabilities: | ||||||||||||||||
Derivative financial instruments - common share warrants | — | 1,950 | — | 1,950 |
As of December 31, 2018 | ||||||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
1.5 Lien Notes | $ | — | $ | — | $ | 272,609 | $ | 272,609 | ||||||||
1.75 Lien Term Loans | — | — | 216,222 | 216,222 | ||||||||||||
Second Lien Term Loans | — | — | 4,185 | 4,185 | ||||||||||||
2018 Notes | 23,330 | — | — | 23,330 | ||||||||||||
2022 Notes | 12,653 | — | — | 12,653 | ||||||||||||
As of December 31, 2017 | ||||||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
1.5 Lien Notes | $ | — | $ | — | $ | 232,276 | $ | 232,276 | ||||||||
1.75 Lien Term Loans | — | — | 372,186 | 372,186 | ||||||||||||
Second Lien Term Loans | — | — | 9,054 | 9,054 | ||||||||||||
2018 Notes | 4,658 | — | — | 4,658 | ||||||||||||
2022 Notes | 2,586 | — | — | 2,586 |
7. | Environmental regulation |
8. | Commitments and contingencies |
(in thousands) | Drilling contracts | Operating leases and other | Other fixed commitments | Total | ||||||||||||
2019 | $ | 3,661 | $ | 1,635 | $ | 17 | $ | 5,313 | ||||||||
2020 | — | 1,595 | 12 | 1,607 | ||||||||||||
2021 | — | 1,193 | 2 | 1,195 | ||||||||||||
2022 | — | 1,173 | — | 1,173 | ||||||||||||
2023 | — | — | — | — | ||||||||||||
Thereafter | — | — | — | — | ||||||||||||
Total | $ | 3,661 | $ | 5,596 | $ | 31 | $ | 9,288 |
• | 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. |
9. | Employee benefit plans |
Year Ended December 31, | ||||||||
(in thousands, except per share data) | 2018 | 2017 | ||||||
Basic net income (loss) per common share: | ||||||||
Net income (loss) | $ | (182,697 | ) | $ | 24,362 | |||
Weighted average common shares outstanding | 21,686 | 21,288 | ||||||
Net income (loss) per basic common share | $ | (8.42 | ) | $ | 1.14 | |||
Diluted net income (loss) per common share: | ||||||||
Net income (loss) | $ | (182,697 | ) | $ | 24,362 | |||
Weighted average common shares outstanding | 21,686 | 21,288 | ||||||
Dilutive effect of: | ||||||||
Restricted shares and restricted share units | — | — | ||||||
Weighted average common shares and common share equivalents outstanding | 21,686 | 21,288 | ||||||
Net income (loss) per diluted common share | $ | (8.42 | ) | $ | 1.14 |
• | Termination of the 2017 Management Incentive Plan - We terminated the 2017 Management Incentive Plan and made pro-rated incentive payments based on the achievement of performance goals as of June 30, 2017. The payments of $1.1 million were made in cash. |
• | Adoption of the KEIP and KERP - We adopted two new cash-based incentive programs beginning on July 1, 2017, including the Key Employee Incentive Plan ("KEIP") for certain officers and Key Employee Retention Plan ("KERP") for employees. The payout of the KEIP is dependent on the achievement of certain performance goals, including production, general and administrative expenses, lease operating expenses, and EBITDA. The payout of the KERP was dependent on the achievement of these performance measures and a fixed percentage of the employees' salary for the first two quarters of the plan until it was converted to be solely based on a fixed percentage of the employees' salary. We incurred $4.8 million in general and administrative expenses related to these plans during 2017. The motion to consider the KERP was approved by the Court on February 22, 2018 and the motion to consider the KEIP was approved by the Court on May 23, 2018. We incurred $4.8 million in general administrative expenses related to these plans during 2018. The KERP is paid on a quarterly basis and the KEIP earned during 2018 will not be paid until the confirmation of a plan of reorganization. Therefore, we accrued $2.2 million related to the KEIP as of December 31, 2018. The term of the KERP was extended to December 31, 2018 and may be extended further at the discretion of the Compensation Committee or the Company, which would be subject to approval as part of the Chapter 11 Cases. The term of the KEIP was extended to December 31, 2018 and further extensions, if any, would be subject to approval as part of the Chapter 11 Cases. |
• | Retention Bonus Agreements - We entered into retention bonus agreements with certain key officers and employees, which resulted in payments of $0.8 million and $7.8 million during 2018 and 2017, respectively. In the event a recipient of a retention bonus voluntarily terminates his or her employment without Good Reason (as defined in each Retention Bonus Agreement), or the Company terminates such recipient’s employment for Cause (as defined in each Retention Bonus Agreement), in either case, before either December 31, 2018 or March 31, 2019 (depending on the agreement with the officer or employee), then such recipient will be required to promptly repay the retention bonus. We recognized $6.3 million and $1.4 million of general and administrative expenses related to these retention bonuses during 2018 and 2017, respectively. The remainder of $0.9 million was recorded as a prepaid asset as of December 31, 2018 and will be recognized over the remaining retention period ending March 31, 2019. |
• | Discontinuation of equity incentive grants - We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there were no grants of share-based compensation during 2018 or 2017. The adoption of the KEIP, KERP and retention bonuses were intended to replace all existing cash-based bonus and equity-based compensation programs. |
Assumption | 2016 | |
Risk-free rate of return | 0.45 - 0.71 % | |
Volatility | 119.83 % | |
Dividend yield | 0.00 % |
Shares | Weighted average grant date fair value per share | ||||||
Non-vested shares/units outstanding at December 31, 2017 | 249,992 | $ | 29.96 | ||||
Granted | — | — | |||||
Vested | — | — | |||||
Forfeited | (3,200 | ) | 25.39 | ||||
Non-vested shares/units outstanding at December 31, 2018 | 246,792 | $ | 30.02 |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Equity-based compensation expense (1) | $ | 2,053 | $ | (11,430 | ) | |||
Equity-based compensation capitalized | 347 | 1,000 | ||||||
Total equity-based compensation | $ | 2,400 | $ | (10,430 | ) |
(1) | Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for ESAS Warrants. |
12. | Income taxes |
Year ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Current: | ||||||||
Federal | $ | — | $ | (1,420 | ) | |||
State | — | — | ||||||
Total current income tax (benefit) | $ | — | $ | (1,420 | ) | |||
Deferred: | ||||||||
Federal | $ | (34,884 | ) | $ | 528,886 | |||
State | (1,028 | ) | (1,496 | ) | ||||
Valuation allowance | 31,394 | (525,674 | ) | |||||
Total deferred income tax (benefit) | (4,518 | ) | 1,716 | |||||
Total income tax (benefit) | $ | (4,518 | ) | $ | 296 |
(in thousands) | December 31, 2018 | December 31, 2017 | ||||||
Deferred tax assets: | ||||||||
Net operating loss carryforwards | $ | 568,976 | $ | 548,701 | ||||
Oil and natural gas properties, gathering assets, and equipment | 178,498 | 236,601 | ||||||
Liabilities subject to compromise | 92,954 | — | ||||||
Other | 43,149 | 58,465 | ||||||
Total deferred tax assets before valuation allowance | 883,577 | 843,767 | ||||||
Valuation allowance | (874,877 | ) | (843,480 | ) | ||||
Total deferred tax assets | 8,700 | 287 | ||||||
Deferred tax liabilities: | ||||||||
Goodwill | $ | (7,205 | ) | $ | (4,518 | ) | ||
Derivative financial instruments | — | (287 | ) | |||||
Other | (1,495 | ) | — | |||||
Total deferred tax liabilities | (8,700 | ) | (4,805 | ) | ||||
Net deferred tax assets (liabilities) | $ | — | $ | (4,518 | ) |
Year Ended December 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
Federal income taxes (benefit) provision at statutory rate | $ | (39,315 | ) | $ | 8,630 | |||
Increases (reductions) resulting from: | ||||||||
Adjustments to the valuation allowance | 31,394 | (525,674 | ) | |||||
Non-deductible compensation | — | 3,206 | ||||||
State taxes net of federal benefit | (1,028 | ) | (1,496 | ) | ||||
Federal and state tax rate change | — | 421,610 | ||||||
Non-deductible interest | 4,814 | 149,577 | ||||||
Non-taxable gain on warrants | (397 | ) | (55,716 | ) | ||||
Other | 14 | 159 | ||||||
Total income tax provision | $ | (4,518 | ) | $ | 296 |
13. | Related party transactions |
14. | Condensed consolidating financial statements |
• | Resources; |
• | the Guarantor Subsidiaries; |
• | the Non-Guarantor Subsidiaries; |
• | elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and |
• | EXCO on a consolidated basis. |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 47,269 | $ | (20,059 | ) | $ | 19,331 | $ | — | $ | 46,541 | |||||||||
Restricted cash | 653 | 15,396 | — | — | 16,049 | |||||||||||||||
Other current assets | 6,671 | 93,305 | 7,577 | — | 107,553 | |||||||||||||||
Total current assets | 54,593 | 88,642 | 26,908 | — | 170,143 | |||||||||||||||
Equity investments | — | — | 4,732 | — | 4,732 | |||||||||||||||
Oil and natural gas properties (full cost accounting method): | ||||||||||||||||||||
Unproved oil and natural gas properties and development costs not being amortized | — | 121,738 | 33,908 | — | 155,646 | |||||||||||||||
Proved developed and undeveloped oil and natural gas properties | 334,709 | 2,924,788 | 73,282 | — | 3,332,779 | |||||||||||||||
Accumulated depletion | (330,776 | ) | (2,494,452 | ) | (6,065 | ) | — | (2,831,293 | ) | |||||||||||
Oil and natural gas properties, net | 3,933 | 552,074 | 101,125 | — | 657,132 | |||||||||||||||
Other property and equipment, net and other non-current assets | 587 | 19,565 | 17,379 | — | 37,531 | |||||||||||||||
Investments in and (advances to) affiliates, net | 379,516 | — | — | (379,516 | ) | — | ||||||||||||||
Goodwill | 13,293 | 149,862 | — | — | 163,155 | |||||||||||||||
Total assets | $ | 451,922 | $ | 810,143 | $ | 150,144 | $ | (379,516 | ) | $ | 1,032,693 | |||||||||
Liabilities and shareholders’ equity | ||||||||||||||||||||
Current maturities of long-term debt | $ | 473,364 | $ | — | $ | — | $ | — | $ | 473,364 | ||||||||||
Other current liabilities | 38,343 | 71,802 | 7,784 | — | 117,929 | |||||||||||||||
Other long-term liabilities | — | 14,825 | 9,588 | — | 24,413 | |||||||||||||||
Liabilities subject to compromise | 966,711 | 476,772 | — | — | 1,443,483 | |||||||||||||||
Payable to parent | — | 2,452,128 | (3,380 | ) | (2,448,748 | ) | — | |||||||||||||
Total shareholders’ equity | (1,026,496 | ) | (2,205,384 | ) | 136,152 | 2,069,232 | (1,026,496 | ) | ||||||||||||
Total liabilities and shareholders’ equity | $ | 451,922 | $ | 810,143 | $ | 150,144 | $ | (379,516 | ) | $ | 1,032,693 |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 49,170 | $ | (9,573 | ) | $ | — | $ | — | $ | 39,597 | |||||||||
Restricted cash | — | 15,271 | — | — | 15,271 | |||||||||||||||
Other current assets | 22,697 | 90,265 | — | — | 112,962 | |||||||||||||||
Total current assets | 71,867 | 95,963 | — | — | 167,830 | |||||||||||||||
Equity investments | — | — | 14,181 | — | 14,181 | |||||||||||||||
Oil and natural gas properties (full cost accounting method): | ||||||||||||||||||||
Unproved oil and natural gas properties and development costs not being amortized | — | 118,652 | — | — | 118,652 | |||||||||||||||
Proved developed and undeveloped oil and natural gas properties | 333,719 | 2,773,847 | — | — | 3,107,566 | |||||||||||||||
Accumulated depletion | (330,777 | ) | (2,421,534 | ) | — | — | (2,752,311 | ) | ||||||||||||
Oil and natural gas properties, net | 2,942 | 470,965 | — | — | 473,907 | |||||||||||||||
Other property and equipment, net and other non-current assets | 892 | 20,382 | — | — | 21,274 | |||||||||||||||
Investments in and (advances to) affiliates, net | 466,055 | — | — | (466,055 | ) | — | ||||||||||||||
Goodwill | 13,293 | 149,862 | — | — | 163,155 | |||||||||||||||
Total assets | $ | 555,049 | $ | 737,172 | $ | 14,181 | $ | (466,055 | ) | $ | 840,347 | |||||||||
Liabilities and shareholders’ equity | ||||||||||||||||||||
Current maturities of long-term debt | $ | 1,362,500 | $ | — | $ | — | $ | — | $ | 1,362,500 | ||||||||||
Other current liabilities | 32,280 | 272,190 | — | — | 304,470 | |||||||||||||||
Derivative financial instruments - common share warrants | 1,950 | — | — | — | 1,950 | |||||||||||||||
Other long-term liabilities | 4,518 | 13,108 | — | — | 17,626 | |||||||||||||||
Payable to parent | — | 2,447,586 | — | (2,447,586 | ) | — | ||||||||||||||
Total shareholders’ equity | (846,199 | ) | (1,995,712 | ) | 14,181 | 1,981,531 | (846,199 | ) | ||||||||||||
Total liabilities and shareholders’ equity | $ | 555,049 | $ | 737,172 | $ | 14,181 | $ | (466,055 | ) | $ | 840,347 |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues: | ||||||||||||||||||||
Oil and natural gas | $ | — | $ | 352,228 | $ | 20,363 | $ | — | $ | 372,591 | ||||||||||
Purchased natural gas and marketing | — | 21,090 | 345 | — | 21,435 | |||||||||||||||
Total revenues | — | 373,318 | 20,708 | — | 394,026 | |||||||||||||||
Costs and expenses: | ||||||||||||||||||||
Oil and natural gas production | — | 54,431 | 2,978 | — | 57,409 | |||||||||||||||
Gathering and transportation | — | 72,772 | 3,403 | — | 76,175 | |||||||||||||||
Purchased natural gas | — | 16,387 | — | — | 16,387 | |||||||||||||||
Depletion, depreciation and amortization | 299 | 73,305 | 6,685 | — | 80,289 | |||||||||||||||
Accretion of liabilities | — | 931 | 1,066 | — | 1,997 | |||||||||||||||
General and administrative | (34,637 | ) | 58,296 | 4,191 | — | 27,850 | ||||||||||||||
Gain on Appalachia JV Settlement | — | — | (119,237 | ) | — | (119,237 | ) | |||||||||||||
Other operating items | (46 | ) | (1,109 | ) | (170 | ) | — | (1,325 | ) | |||||||||||
Total costs and expenses | (34,384 | ) | 275,013 | (101,084 | ) | — | 139,545 | |||||||||||||
Operating income | 34,384 | 98,305 | 121,792 | — | 254,481 | |||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest expense, net | (33,917 | ) | — | — | — | (33,917 | ) | |||||||||||||
Loss on derivative financial instruments - commodity derivatives | (615 | ) | — | — | — | (615 | ) | |||||||||||||
Gain on derivative financial instruments - common share warrants | 1,889 | — | — | — | 1,889 | |||||||||||||||
Other income | 27 | 37 | 6 | — | 70 | |||||||||||||||
Equity income | — | — | 175 | — | 175 | |||||||||||||||
Reorganization items, net | (101,284 | ) | (308,014 | ) | — | — | (409,298 | ) | ||||||||||||
Net loss from consolidated subsidiaries | (87,699 | ) | — | — | 87,699 | — | ||||||||||||||
Total other income (expense) | (221,599 | ) | (307,977 | ) | 181 | 87,699 | (441,696 | ) | ||||||||||||
Income (loss) before income taxes | (187,215 | ) | (209,672 | ) | 121,973 | 87,699 | (187,215 | ) | ||||||||||||
Income tax benefit | (4,518 | ) | — | — | — | (4,518 | ) | |||||||||||||
Net income (loss) | $ | (182,697 | ) | $ | (209,672 | ) | $ | 121,973 | $ | 87,699 | $ | (182,697 | ) |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues: | ||||||||||||||||||||
Oil and natural gas | $ | — | $ | 258,830 | $ | — | $ | — | $ | 258,830 | ||||||||||
Purchased natural gas and marketing | — | 24,816 | — | — | 24,816 | |||||||||||||||
Total revenues | — | 283,646 | — | — | 283,646 | |||||||||||||||
Costs and expenses: | ||||||||||||||||||||
Oil and natural gas production | — | 48,142 | — | — | 48,142 | |||||||||||||||
Gathering and transportation | — | 111,427 | — | — | 111,427 | |||||||||||||||
Purchased natural gas | — | 23,400 | — | — | 23,400 | |||||||||||||||
Depletion, depreciation and amortization | 298 | 50,742 | — | — | 51,040 | |||||||||||||||
Accretion of liabilities | — | 874 | — | — | 874 | |||||||||||||||
General and administrative | (30,224 | ) | 60,389 | — | — | 30,165 | ||||||||||||||
Other operating items | 553 | 58,601 | — | — | 59,154 | |||||||||||||||
Total costs and expenses | (29,373 | ) | 353,575 | — | — | 324,202 | ||||||||||||||
Operating income (loss) | 29,373 | (69,929 | ) | — | — | (40,556 | ) | |||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest expense, net | (108,173 | ) | (2 | ) | — | — | (108,175 | ) | ||||||||||||
Gain on derivative financial instruments - commodity derivatives | 24,732 | — | — | — | 24,732 | |||||||||||||||
Gain on derivative financial instruments - common share warrants | 159,190 | — | — | — | 159,190 | |||||||||||||||
Loss on restructuring of debt | (6,380 | ) | — | — | — | (6,380 | ) | |||||||||||||
Other income | 30 | 1 | — | — | 31 | |||||||||||||||
Equity loss | — | — | (4,184 | ) | — | (4,184 | ) | |||||||||||||
Net loss from consolidated subsidiaries | (74,114 | ) | — | — | 74,114 | — | ||||||||||||||
Total other income (expense) | (4,715 | ) | (1 | ) | (4,184 | ) | 74,114 | 65,214 | ||||||||||||
Income (loss) before income taxes | 24,658 | (69,930 | ) | (4,184 | ) | 74,114 | 24,658 | |||||||||||||
Income tax expense | 296 | — | — | — | 296 | |||||||||||||||
Net income (loss) | $ | 24,362 | $ | (69,930 | ) | $ | (4,184 | ) | $ | 74,114 | $ | 24,362 |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Operating Activities: | ||||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (22,984 | ) | $ | 148,311 | $ | 8,669 | $ | — | $ | 133,996 | |||||||||
Investing Activities: | ||||||||||||||||||||
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions | (1,047 | ) | (164,164 | ) | 14,044 | — | (151,167 | ) | ||||||||||||
Other | — | 950 | — | — | 950 | |||||||||||||||
Advances/investments with affiliates | (1,160 | ) | 4,542 | (3,382 | ) | — | — | |||||||||||||
Net cash provided by (used in) investing activities | (2,207 | ) | (158,672 | ) | 10,662 | — | (150,217 | ) | ||||||||||||
Financing Activities: | ||||||||||||||||||||
Borrowings under DIP Credit Agreement | 156,406 | — | — | — | 156,406 | |||||||||||||||
Repayments under EXCO Resources Credit Agreement | (126,401 | ) | — | — | — | (126,401 | ) | |||||||||||||
Debt financing costs and other | (6,062 | ) | — | — | — | (6,062 | ) | |||||||||||||
Net cash provided by financing activities | 23,943 | — | — | — | 23,943 | |||||||||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (1,248 | ) | (10,361 | ) | 19,331 | — | 7,722 | |||||||||||||
Cash, cash equivalents and restricted cash at beginning of period | 49,170 | 5,698 | — | — | 54,868 | |||||||||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 47,922 | $ | (4,663 | ) | $ | 19,331 | $ | — | $ | 62,590 |
(in thousands) | Resources | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Operating Activities: | ||||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (22,761 | ) | $ | 77,172 | $ | — | $ | — | $ | 54,411 | |||||||||
Investing Activities: | ||||||||||||||||||||
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions | (1,347 | ) | (169,820 | ) | — | — | (171,167 | ) | ||||||||||||
Proceeds from disposition of property and equipment | — | 350 | — | — | 350 | |||||||||||||||
Net changes in amounts due to joint ventures | — | (9,161 | ) | — | — | (9,161 | ) | |||||||||||||
Equity investments and other | — | 1,548 | — | — | 1,548 | |||||||||||||||
Advances/investments with affiliates | (110,001 | ) | 110,001 | — | — | — | ||||||||||||||
Net cash used in investing activities | (111,348 | ) | (67,082 | ) | — | — | (178,430 | ) | ||||||||||||
Financing Activities: | ||||||||||||||||||||
Borrowings under EXCO Resources Credit Agreement | 163,401 | — | — | — | 163,401 | |||||||||||||||
Repayments under EXCO Resources Credit Agreement | (265,592 | ) | — | — | — | (265,592 | ) | |||||||||||||
Proceeds received from issuance of 1.5 Lien Notes, net | 295,530 | — | — | — | 295,530 | |||||||||||||||
Payments on Second Lien Term Loans | (11,602 | ) | — | — | — | (11,602 | ) | |||||||||||||
Payments of common share dividends | (6 | ) | — | — | — | (6 | ) | |||||||||||||
Debt financing costs and other | (23,062 | ) | — | — | — | (23,062 | ) | |||||||||||||
Net cash provided by financing activities | 158,669 | — | — | — | 158,669 | |||||||||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | 24,560 | 10,090 | — | — | 34,650 | |||||||||||||||
Cash, cash equivalents and restricted cash at beginning of period | 24,610 | (4,392 | ) | — | — | 20,218 | ||||||||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 49,170 | $ | 5,698 | $ | — | $ | — | $ | 54,868 |
15. | Quarterly financial data (unaudited) |
Quarter | ||||||||||||||||
(in thousands, except per share amounts) | 1st | 2nd | 3rd | 4th | ||||||||||||
2018 | ||||||||||||||||
Total revenues | $ | 90,464 | $ | 98,130 | $ | 98,571 | $ | 106,861 | ||||||||
Operating income (loss) (1) | 146,737 | 30,399 | 31,121 | 46,224 | ||||||||||||
Net income (loss) | $ | (211,049 | ) | $ | 7,744 | $ | 3,684 | $ | 16,924 | |||||||
Basic earnings (loss) per share: | ||||||||||||||||
Net income (loss) | $ | (9.64 | ) | $ | 0.36 | $ | 0.17 | $ | 0.78 | |||||||
Weighted average shares | 21,902 | 21,615 | 21,616 | 21,616 | ||||||||||||
Diluted earnings (loss) per share: | ||||||||||||||||
Net income (loss) | $ | (9.64 | ) | $ | 0.36 | $ | 0.17 | $ | 0.78 | |||||||
Weighted average shares | 21,902 | 21,615 | 21,616 | 21,616 | ||||||||||||
2017 | ||||||||||||||||
Total revenues | $ | 76,529 | $ | 71,015 | $ | 66,736 | $ | 69,366 | ||||||||
Operating income (loss) (2) | 13,587 | 15,216 | (5,142 | ) | (64,217 | ) | ||||||||||
Net income (loss) (3) | $ | 8,193 | $ | 120,750 | $ | (18,824 | ) | $ | (85,757 | ) | ||||||
Basic earnings (loss) per share: | ||||||||||||||||
Net income (loss) | $ | 0.44 | $ | 6.13 | $ | (0.81 | ) | $ | (3.68 | ) | ||||||
Weighted average shares | 18,726 | 19,702 | 23,319 | 23,333 | ||||||||||||
Diluted earnings (loss) per share: | ||||||||||||||||
Net income (loss) | $ | 0.44 | $ | 6.07 | $ | (0.81 | ) | $ | (3.68 | ) | ||||||
Weighted average shares | 18,749 | 19,886 | 23,319 | 23,333 |
(1) | Operating income for the first quarter of 2018 includes the gain of $119.5 million recognized in connection with the Appalachia JV Settlement. Operating income during 2018 was significantly impacted by costs associated with the Chapter 11 process, which includes $352.9 million, $16.4 million, $18.2 million and $21.8 million during the first, second, third, and fourth quarters of 2018, respectively, that were classified as “Reorganization items, net” in our Consolidated Statement of Operations. See "Note 1. Organization and basis of presentation" for further discussion. |
(2) | Operating loss for the fourth quarter of 2017 includes the acceleration of the remaining charges under a firm transportation agreement of $56.4 million. See "Note 8. Commitments and contingencies" for further discussion. |
(3) | Net income (loss) includes gains on the revaluation of the 2017 Warrants of $6.0 million, $122.3 million, $18.3 million and $12.6 million during the first, second, third, and fourth quarters of 2017, respectively, primarily due to a decrease in EXCO's share price. See "Note 4. Derivative financial instruments" for further discussion. |
16. | Supplemental information relating to oil and natural gas producing activities (unaudited) |
(in thousands, except per unit amounts) | Amount | |||
2018: | ||||
Proved property acquisition costs (1) | $ | — | ||
Unproved property acquisition costs (1) | — | |||
Total property acquisition costs | — | |||
Development | 146,834 | |||
Exploration costs | — | |||
Lease acquisitions and other | 9,931 | |||
Capitalized asset retirement costs | — | |||
Depletion per Boe | $ | 4.44 | ||
Depletion per Mcfe | $ | 0.74 | ||
2017: | ||||
Proved property acquisition costs | $ | 18,940 | ||
Unproved property acquisition costs | 5,228 | |||
Total property acquisition costs | 24,168 | |||
Development | 128,323 | |||
Exploration costs (2) | 19,538 | |||
Lease acquisitions and other | 5,654 | |||
Capitalized asset retirement costs | 12 | |||
Depletion per Boe | $ | 3.45 | ||
Depletion per Mcfe | $ | 0.57 |
(1) | The Appalachia JV Settlement resulted in the acquisition of $33.5 million and $72.5 million of unproved and proved oil and natural gas properties, respectively. Per the terms of the settlement agreement, the acquisition of interests in these oil and gas properties did not require us to transfer any cash consideration. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion of the Appalachia JV Settlement. |
(2) | Exploration costs in 2017 related to the wells drilled in the Bossier shale in North Louisiana. |
Oil (Mbbls) | Natural Gas (Mmcf) | Mmcfe | |||||||
December 31, 2016 | 10,168 | 415,719 | 476,727 | ||||||
Purchase of reserves in place (1) | — | 50,456 | 50,456 | ||||||
Discoveries and extensions | 13 | 21,880 | 21,958 | ||||||
Revisions of previous estimates: | |||||||||
Changes in price | 679 | 30,200 | 34,274 | ||||||
Performance and other factors (2) | (290 | ) | 72,332 | 70,593 | |||||
Sales of reserves in place | — | — | — | ||||||
Production | (1,158 | ) | (80,136 | ) | (87,084 | ) | |||
December 31, 2017 | 9,412 | 510,451 | 566,924 | ||||||
Purchase of reserves in place (3) | — | 118,415 | 118,415 | ||||||
Discoveries and extensions | 1,387 | 22,482 | 30,804 | ||||||
Revisions of previous estimates: | — | ||||||||
Changes in price | 690 | 5,726 | 9,866 | ||||||
Performance and other factors (4) | 3,170 | 22,486 | 41,502 | ||||||
Sales of reserves in place | — | — | — | ||||||
Production | (1,357 | ) | (98,779 | ) | (106,921 | ) | |||
December 31, 2018 | 13,302 | 580,781 | 660,590 |
Oil (Mbbls) | Natural Gas (Mmcf) | Mmcfe | |||||||
Proved developed: | |||||||||
December 31, 2018 | 13,302 | 580,781 | 660,590 | ||||||
December 31, 2017 | 9,412 | 510,451 | 566,924 | ||||||
Proved undeveloped: | |||||||||
December 31, 2018 | — | — | — | ||||||
December 31, 2017 | — | — | — |
(1) | Purchases of reserves in place during 2017 primarily related to the acquisition of incremental interests in certain oil and natural gas properties that we operate and undeveloped acreage in the North Louisiana region. |
(2) | Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2017 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana region. |
(3) | Purchases of reserves in place during 2018 related to the acquisition of incremental interests in the Appalachia JV Settlement on February 27, 2018. The Proved Reserves acquired in the Appalachia JV Settlement predominantly consists of proved producing properties in the Marcellus shale. |
(4) | Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2018 that were previously reclassified to unproved reserves in prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisiana and South Texas regions. |
(in thousands) | Amount | |||
Year Ended December 31, 2018: | ||||
Future cash inflows | $ | 2,335,662 | ||
Future production costs | 1,048,606 | |||
Future development costs (1) | 65,033 | |||
Future income taxes (2) | — | |||
Future net cash flows | 1,222,023 | |||
Discount of future net cash flows at 10% per annum | 464,654 | |||
Standardized measure of discounted future net cash flows | $ | 757,369 | ||
Year Ended December 31, 2017: | ||||
Future cash inflows | $ | 1,690,056 | ||
Future production costs | 863,847 | |||
Future development costs (1) | 51,925 | |||
Future income taxes (2) | — | |||
Future net cash flows | 774,284 | |||
Discount of future net cash flows at 10% per annum | 291,537 | |||
Standardized measure of discounted future net cash flows | $ | 482,747 |
(1) | All of our Proved Undeveloped Reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2018 and 2017. As such, future development costs at December 31, 2018 and 2017 consist primarily of estimated future plugging and abandonment costs. |
(2) | Our tax basis in oil and natural gas properties exceeded the pre-tax cash inflows at December 31, 2018 and 2017. As a result, we are not expected to generate future taxable income from our oil and natural gas properties in the preparation of the Standardized Measure. |
(in thousands) | Amount | |||
Year Ended December 31, 2018: | ||||
Sales and transfers of oil and natural gas produced | $ | (239,007 | ) | |
Net changes in prices and production costs | 192,798 | |||
Extensions and discoveries, net of future development and production costs | 70,394 | |||
Development costs during the period to the extent previously estimated | 6,192 | |||
Changes in estimated future development costs | (6,314 | ) | ||
Revisions of previous quantity estimates | 136,700 | |||
Sales of reserves in place | — | |||
Purchase of reserves in place | 63,146 | |||
Accretion of discount | 48,275 | |||
Changes in timing and other | 2,438 | |||
Net change in income taxes | — | |||
Net change | $ | 274,622 | ||
Year Ended December 31, 2017: | ||||
Sales and transfers of oil and natural gas produced | $ | (99,260 | ) | |
Net changes in prices and production costs | 91,998 | |||
Extensions and discoveries, net of future development and production costs | 25,459 | |||
Development costs during the period to the extent previously estimated | 1,913 | |||
Changes in estimated future development costs | (4,758 | ) | ||
Revisions of previous quantity estimates | 88,825 | |||
Sales of reserves in place | — | |||
Purchase of reserves in place | 40,991 | |||
Accretion of discount | 31,093 | |||
Changes in timing and other | (4,444 | ) | ||
Net change in income taxes | — | |||
Net change | $ | 171,817 |
(in thousands) | Total | 2018 | 2017 | 2016 | 2015 and prior | |||||||||||||||
Property acquisition costs | $ | 104,465 | $ | 33,908 | $ | 10,890 | $ | 899 | $ | 58,768 | ||||||||||
Exploration and development | 13,900 | 13,900 | — | — | — | |||||||||||||||
Capitalized interest | 37,281 | 3,357 | 6,440 | 5,213 | 22,271 | |||||||||||||||
Total | $ | 155,646 | $ | 51,165 | $ | 17,330 | $ | 6,112 | $ | 81,039 |
17. | Subsequent events |
• | All claims filed by CEC and CEML in the Chapter 11 Cases shall be deemed disallowed and expunged. These claims primarily include costs related to the rejection of a marketing agreement in the North Louisiana region and pre-petition costs related to sales of natural gas in the South Texas region. As of December 31, 2018, our estimate of the allowable claims classified as "Liabilities subject to compromise" was $8.6 million for the rejection of the marketing agreement and $2.0 million pre-petition costs related to sales of natural gas; |
• | EXCO agreed to release CEC and CEML from pre-petition litigation including the wrongful termination of a natural gas sales contract in South Texas and improper charges for post-production costs in North Louisiana. See further discussion of the litigation with CEC and CEML in "Item 3. Legal proceedings"; and |
• | EXCO will assume certain sales contracts with CEML and joint operating agreements with CEC. |
• | The proofs of claim filed by EPD in the Chapter 11 Cases shall be settled for an allowed general unsecured claim of $10.0 million. These claims primarily include costs related to the rejection of a natural gas sales agreement and natural gas transportation agreement in the North Louisiana region. On the effective date of a plan of reorganization, Bluescape shall be required to purchase the claim from EPD for $5.0 million; |
• | The Debtors shall pay EPD: (i) $6.25 million on the effective date of a plan of reorganization, and (ii) $6.25 million on September 1, 2019; and |
• | Upon completion of the payments from the Debtors and Bluescape to EPD, each party shall provide releases and take all actions to dismiss the aforementioned litigation. |
Exhibit Number | Description of Exhibits | |
3.1 | ||
3.2 | ||
4.1 | ||
4.2 | ||
4.3 | ||
4.4 | ||
4.5 | ||
4.6 | ||
4.7 | ||
4.8 | ||
4.9 | ||
4.10 | ||
4.11 | ||
4.12 | ||
4.13 | ||
4.14 | ||
4.15 | ||
4.16 | ||
4.17 | ||
4.18 | ||
4.19 | ||
4.20 | ||
4.21 | ||
4.22 | ||
10.1 | ||
10.2 | ||
10.3 | ||
10.4 | ||
10.5 | ||
10.6 | ||
10.7 | ||
10.8 | ||
10.9 | ||
10.10 | ||
10.11 | ||
10.12 | ||
10.13 | ||
10.14 | ||
10.15 | ||
10.16 | ||
10.17 | ||
10.18 | ||
10.19 |
10.20 | ||
10.21 | ||
10.22 | ||
10.23 | ||
10.24 | ||
10.25 | ||
10.26 | ||
10.27 | ||
10.28 | ||
10.29 | ||
10.30 | ||
10.31 | ||
10.32 | ||
10.33 | ||
10.34 | ||
10.35 | ||
10.36 | ||
10.37 | ||
10.38 | ||
10.39 | ||
10.40 | ||
10.41 | ||
10.42 | ||
10.43 | ||
10.44 | ||
10.45 | ||
10.46 | ||
10.47 | ||
10.48 | ||
10.49 | ||
10.50 | ||
10.51 | ||
10.52 | ||
10.53 | ||
10.54 | ||
10.55 | ||
10.56 | ||
10.57 | ||
10.58 | ||
10.59 | ||
10.60 | ||
10.61 | ||
10.62 | ||
10.63 | ||
10.64 | ||
10.65 | ||
10.66 | ||
10.67 | ||
10.68 | ||
10.69 | ||
10.70 | ||
10.71 | ||
Date: | March 18, 2019 | EXCO RESOURCES, INC. | |
(Registrant) | |||
/s/ Harold L. Hickey | |||
Harold L. Hickey | |||
Chief Executive Officer and President | |||
(Principal Executive Officer) | |||
Date: | March 18, 2019 | /s/ Harold L. Hickey | |
Harold L. Hickey | |||
Chief Executive Officer and President | |||
(Principal Executive Officer) | |||
/s/ Tyler S. Farquharson | |||
Tyler S. Farquharson | |||
Vice President, Chief Financial Officer and Treasurer | |||
(Principal Financial Officer) | |||
/s/ Brian N. Gaebe | |||
Brian N. Gaebe | |||
Chief Accounting Officer and Corporate Controller | |||
(Principal Accounting Officer) | |||
/s/ Anthony R. Horton | |||
Anthony R. Horton | |||
Director | |||
/s/ Randall E. King | |||
Randall E. King | |||
Director | |||
/s/ Robert L. Stillwell | |||
Robert L. Stillwell | |||
Director |
Name of Subsidiary | State of Incorporation | |
EXCO Appalachia Midstream, LLC | Delaware | |
EXCO GP Partners Old, LP | Delaware | |
EXCO Holding (PA), Inc. | Delaware | |
EXCO Holding MLP, Inc. | Texas | |
EXCO Land Company, LLC | Delaware | |
EXCO Mid-Continent MLP, LLC | Delaware | |
EXCO Operating Company, LP | Delaware | |
EXCO Partners GP, LLC | Delaware | |
EXCO Partners OLP GP, LLC | Delaware | |
EXCO Production Company (PA), LLC | Delaware | |
EXCO Production Company (WV), LLC | Delaware | |
EXCO Resources (PA), LLC | Delaware | |
EXCO Resources (XA), LLC | Delaware | |
EXCO Services, Inc. | Delaware | |
Raider Marketing GP, LLC | Delaware | |
Raider Marketing, LP | Delaware | |
EXCO Production Company (PA) II, LLC | Delaware | |
EXCO Production Company (WV) II, LLC | Delaware |
1. | I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | March 18, 2019 | /s/ Harold L. Hickey |
Harold L. Hickey | ||
Chief Executive Officer and President |
1. | I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | March 18, 2019 | /s/ Tyler Farquharson |
Tyler Farquharson | ||
Vice President, Chief Financial Officer and Treasurer |
Date: | March 18, 2019 | /s/ Harold L. Hickey |
Harold L. Hickey | ||
Chief Executive Officer and President | ||
/s/ Tyler Farquharson | ||
Tyler Farquharson | ||
Vice President, Chief Financial Officer and Treasurer |
Net Reserves | Future Net Revenue (M$) | |||||||
Gas | Condensate | Present Worth | ||||||
Category | (MMCF) | (MBBL) | Total | at 10% | ||||
Proved Developed Producing | 562,453.6 | 14.0 | 702,082.3 | 447,666.2 | ||||
Proved Developed Non-Producing | 5,962.5 | 0.0 | 6,446.2 | 3,998.2 | ||||
Total Proved Developed | 568,416.1 | 14.0 | 708,528.5 | 451,664.3 | ||||
Totals may not add because of rounding. |
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(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. |
(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. |
Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. |
(i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
(ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
(iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
(iv) | Provide improved recovery systems. |
(i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. |
(ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
(iii) | Dry hole contributions and bottom hole contributions. |
(iv) | Costs of drilling and equipping exploratory wells. |
(v) | Costs of drilling exploratory-type stratigraphic test wells. |
(i) | Oil and gas producing activities include: |
(A) | The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; |
(B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
(C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
(1) | Lifting the oil and gas to the surface; and |
(2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
(D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
(ii) | Oil and gas producing activities do not include: |
(A) | Transporting, refining, or marketing oil and gas; |
(B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
(C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
(D) | Production of geothermal steam. |
(i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
(iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
(ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
(iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
(A) | Costs of labor to operate the wells and related equipment and facilities. |
(B) | Repairs and maintenance. |
(C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
(D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
(E) | Severance taxes. |
(ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any, and |
(B) | 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. |
(ii) | 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. |
(iii) | 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. |
(iv) | 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: |
(A) | 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 |
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | 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. |
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
(i) | 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. |
(ii) | 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. |
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); The company's historical record at completing development of comparable long-term projects; The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
(iii) | 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
/s/ Michael F. Stell |
Michael F. Stell, P.E. |
TBPE License No. 56416 |
Advising Senior Vice President |
TBPE REGISTERED ENGINEERING FIRM F-1580 | FAX (713) 651-0849 | |||
1100 LOUISIANA SUITE 4600 | HOUSTON, TEXAS 77002-5294 | TELEPHONE (713) 651-9191 |
As of December 31, 2018 |
Total Proved | ||||
Developed | ||||
Producing | ||||
Net Remaining Reserves | ||||
Oil/Condensate – Barrels | 13,287,579 | |||
Gas – MMcf | 10,327 | |||
Income Data ($M) | ||||
Future Gross Revenue | $789,816 | |||
Deductions | 271,113 | |||
Future Net Income (FNI) | $518,703 | |||
Discounted FNI @ 10% | $304,932 |
Discounted Future Net Income ($M) | ||||||
As of December 31, 2018 | ||||||
Discount Rate | Total | |||||
Percent | Proved | |||||
5 | $ | 381,380 | ||||
15 | $ | 256,943 | ||||
20 | $ | 224,112 | ||||
25 | $ | 200,211 |
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices |
North America | ||||
United States | Oil/Condensate | WTI Cushing | $65.56/bbl | $64.81/bbl |
Gas | Henry Hub | $3.10/MMBTU | $1.81/Mcf |
(1) | completion intervals that are open at the time of the estimate but which have not yet started producing; |
(2) | wells which were shut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |