EXCO Resources, Inc. Reports Fourth Quarter and Full Year 2012 Results
EXCO Resources, Inc. Reports Fourth Quarter and Full Year 2012 Results
- Adjusted net income, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and items typically not included by securities analysts in published estimates, was $0.17 per diluted share for the fourth quarter 2012 compared to $0.09 per diluted share for the fourth quarter 2011. Adjusted net income for the full year 2012 was $0.38 per diluted share compared to $0.56 per diluted share for the full year 2011.
- GAAP results were a net loss of $269 million, or $1.25 per diluted share, for the fourth quarter 2012 and a net loss of $1.4 billion, or $6.50 per diluted share, for the full year 2012. The fourth quarter and full year 2012 include a $324 million and $1.3 billion, respectively, pre-tax non-cash ceiling test write-down of oil and natural gas properties.
- Oil, natural gas and natural gas liquids (NGL) revenues, before cash settlements on derivatives, for the fourth quarter 2012 were $152 million compared with fourth quarter 2011 revenues of $179 million. Our average sales price per Mcfe decreased to $3.47 per Mcfe for the fourth quarter 2012 from $3.49 in the prior year's quarter. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $192 million for the fourth quarter 2012, compared with $231 million in the fourth quarter 2011. Oil, natural gas and NGL revenues for the full year 2012, excluding derivatives, were $547 million and $749 million when settlements from derivatives are included. Revenues for the full year 2011 were $754 million, excluding derivatives, and $890 million inclusive of cash settlements from derivatives.
- Adjusted earnings before interest, taxes, depreciation, depletion and amortization, ceiling test write-downs and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the fourth quarter 2012 was $122 million compared with $151 million in the prior year's quarter and $468 million for the full year 2012 compared with $605 million for the full year 2011.
- Oil, natural gas and NGL production was 44 Bcfe, or 477 Mmcfe per day, for the fourth quarter 2012 compared with 512 Mmcfe per day in the third quarter 2012 and 556 Mmcfe per day in the fourth quarter 2011. The declines in production reflect the impacts of our reduced drilling program. At the end of 2011, we had 24 operated drilling rigs throughout our operating regions. During 2012, we reduced that operated rig count to five. Fourth quarter 2012 production from our Haynesville/Bossier shale was 334 Mmcf per day compared with 407 Mmcf per day in the prior year's quarter. Year over year production increased 5% in our Haynesville/Bossier shale area. Fourth quarter 2012 production in our Appalachia region was 50 Mmcfe per day, a 22% increase from fourth quarter 2011. Year over year production increased 30% in our Appalachia region. The increase reflects impacts from our horizontal drilling of Marcellus shale wells. Permian production was flat year over year and compared to prior quarters.
- Our direct operating costs were $0.41 per Mcfe for the fourth quarter 2012 compared with $0.47 per Mcfe for the fourth quarter 2011. We continue taking significant steps in reducing our operating costs in all operating areas in response to the low natural gas price environment. Specific actions implemented during 2012 include shutting in certain marginal producing wells, reducing compressor rentals, renegotiating water disposal arrangements and modifying chemical treatment programs.
- TGGT's average throughput was approximately 1.4 Bcf per day during the fourth quarter 2012, compared with 1.5 Bcf per day during the fourth quarter 2011. Our 50% share of TGGT's adjusted net income in the fourth quarter 2012 was $13 million, after adjustments for certain non-cash items during the quarter, compared to $10 million during the fourth quarter 2011.
- On February 14, 2013, we formed a partnership with Harbinger Group Inc. (HGI). Pursuant to the definitive agreements governing the transaction, we contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin in West Texas to the partnership in exchange for cash consideration of $573 million, after customary preliminary purchase price adjustments, a 24.5% limited partner interest and a 50% interest in the general partner of the partnership. After giving effect to the 2.0% general partner interest in the partnership, we own an economic interest of 25.5% in the partnership. Proceeds received from the formation of the partnership were used to reduce outstanding borrowings under our credit agreement. The partnership has its own credit facility with an initial borrowing base of $400 million to fund its operations and seek accretive acquisitions. Following are selected operating data and financial metrics for 2012 reflecting the pro forma impacts to EXCO for the full year 2012 from the formation of the partnership with HGI:
|Pro forma adjustments|
|(dollars in thousands, except per unit rate)||Historical EXCO||Total Partnership||EXCO's 25.5% share||Pro forma EXCO|
|Reserves (as of December 31, 2012):|
|Total proved (Mmcfe)||1,009,386||(404,789||)||103,221||707,818|
|Total production (Mmcfe)||189,928||(36,647||)||9,345||162,626|
|Average production (Mmcfe/d)||519||(100||)||26||445|
|Revenues, excluding derivatives||$||546,609||$||(159,447||)||$||40,659||$||427,821|
|Average realized price ($/Mcfe)||2.88||4.35||4.35||2.63|
|Direct operating costs||77,127||(46,824||)||11,940||42,243|
|Production and ad valorem taxes||27,483||(18,956||)||4,834||13,361|
|Gathering and transportation||102,875||(12,841||)||3,275||93,309|
|Excess of revenues over operating expenses||$||339,124||$||(80,826||)||$||20,610||$||278,908|
Douglas H. Miller, EXCO's Chief Executive Officer, commented, "We recognized that 2012 would be a difficult year in terms of natural gas prices so we undertook actions to position ourselves to meet the challenges low prices present. We reduced our drilling rig count from 24 rigs at year-end 2011 to five at the end of 2012. We reduced our employee headcount by 16% and our contractor headcount by 62%. We took other aggressive cost cutting measures as well, reducing our capital spending by 48%, our direct operating expenses by 11% on a per Mcfe basis, and our general and administrative costs by 23% on a per Mcfe basis, year over year. In spite of the decreased drilling and spending, our production increased 3% year over year.
"In addition to significant cost reductions, we also negotiated and entered into a private limited partnership with Harbinger Group, Inc. which provided us with $573 million to reduce our debt as well as a 25.5% ongoing interest and a vehicle to conduct conventional asset acquisitions in the future.
"We intend to pursue producing property acquisitions during 2013 across core and new areas, and also plan to engage partners to provide financial support for undrilled locations and drilling costs associated with future acquisitions. We are convinced that the economics of producing property acquisitions are presently superior to drill bit economics.
"We are encouraged that natural gas prices have increased since the 2nd quarter 2012 and are optimistic about the future of the natural gas industry in general and our prospects for the future. We begin 2013 with significant liquidity, a much better price than the average realized in 2012 and an acquisition strategy which should produce stronger results.
"We appreciate the tremendous efforts of our employees and contractors during the difficult year just completed, we are grateful for the support of our Directors and Shareholders, and we look forward to implementing our strategy during 2013 and beyond to improve our results."
Our reported net income (loss) shown below, a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. The following table provides a reconciliation of our net income (loss) to the non-GAAP measure of adjusted net income:
|Three Months Ended||Years Ended|
|December 31, 2012||December 31, 2011||December 31, 2012||December 31, 2011|
|(in thousands, except per share amounts)||Amount||Per share||Amount||Per share||Amount||Per share||Amount||Per share|
|Net income (loss), GAAP||$||(269,029||)||$||(166,652||)||$||(1,393,285||)||$||22,596|
|Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes||(8,394||)||(36,425||)||135,945||(84,313||)|
|Non-cash write down of oil and natural gas properties, before taxes||324,040||233,239||1,346,749||233,239|
|Adjustments included in equity income||5,405||—||27,088||—|
|Non-recurring other operating items||8,200||118||17,928||27,660|
|Deferred finance cost amortization acceleration||—||1,689||3,000||1,689|
|Income taxes on above adjustments (1)||(131,700||)||(79,448||)||(612,284||)||(71,310||)|
|Adjustment to deferred tax asset valuation allowance (2)||107,612||66,661||557,314||(9,036||)|
|Total adjustments, net of taxes||305,163||185,834||1,475,740||97,929|
|Adjusted net income||$||36,134||$||19,182||$||82,455||$||120,525|
|Net income (loss), GAAP (3)||$||(269,029||)||$||(1.25||)||$||(166,652||)||$||(0.78||)||$||(1,393,285||)||$||(6.50||)||$||22,596||$||0.11|
|Adjustments shown above (3)||305,163||1.42||185,834||0.87||1,475,740||6.88||97,929||0.46|
|Dilution attributable to stock options (4)||—||—||—||—||—||—||—||(0.01||)|
|Adjusted net income||$||36,134||$||0.17||$||19,182||$||0.09||$||82,455||$||0.38||$||120,525||$||0.56|
|Common stock and equivalents used for earnings per share (EPS):|
|Weighted average common shares outstanding||214,672||214,137||214,321||213,908|
|Dilutive stock options||816||1,479||—||2,797|
|Shares used to compute diluted EPS for adjusted net income||215,488||215,616||214,321||216,705|
(1) The assumed income tax rate is 40% for all periods.
(2) Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.
(3) Per share amounts are based on weighted average number of common shares outstanding.
(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options.
Our cash flow from operations before changes in working capital was $105 million for the fourth quarter 2012. We use our cash flow and available borrowing capacity in our credit agreement to fund our drilling and development programs and acquire producing properties.
|Three Months Ended||Years Ended|
|December 31,||December 31,|
|Cash flow from operations, GAAP||$||100,009||$||73,209||$||514,786||$||428,543|
|Net change in working capital||(2,621||)||64,551||(126,937||)||103,973|
|Non-recurring other operating items||8,000||(474||)||16,625||21,339|
|Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1)||$||105,388||$||137,286||$||404,474||$||553,855|
(1) Cash flow from operations before working capital changes and non-recurring other operating items are presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company's ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities.
Operations activity and outlook
We spent $77 million on development and exploitation activities, drilling and completing 43 gross (18.9 net) operated wells in the fourth quarter 2012, compared with 38 gross (18.2 net) operated wells during the third quarter 2012. In addition, we participated in 1 gross (0.2 net) well operated by others (OBO) during the fourth quarter 2012. We had an overall drilling success rate of 98% for the fourth quarter 2012. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $125 million in the fourth quarter 2012 and approximately $500 million for the full year 2012. We spent $403 million of net capital on full year 2012 development and exploration activities as we drilled and completed 175 gross (76.0 net) wells during 2012.
Our actual capital expenditures for the fourth quarter 2012, the full year 2012 and our 2013 capital budget are presented in the following table:
|(in thousands)||Fourth Quarter||Full Year||2013 Budget|
|Gas gathering and water pipelines||39||1,044||1,000|
|Lease acquisitions and seismic (1)||37,925||47,025||17,000|
|Corporate and other||5,264||24,494||16,000|
(1) Net of acreage reimbursements from BG Group totaling $2.1 million during 2012.
The 2013 capital budget, as approved by our Board of Directors, is highly dependent upon natural gas prices and is therefore subject to change. Further, our renewed focus on acquisitions of producing properties and our interest in obtaining outside participation in certain of our drilling activities and acquisitions of drilling locations could have an impact on the 2013 approved capital budget. We will update our capital spending plans on a quarterly basis during the year.
Our horizontal Haynesville shale development program continues to be a significant asset for EXCO and continues to yield strong results. As of December 31, 2012, our Haynesville/Bossier shale operated production was 1,096 Mmcf per day gross (328.1 Mmcf per day net) and with the addition of production from our OBO wells, we had 353.0 Mmcf per day net of total Haynesville/Bossier shale production. In response to low natural gas prices, we have significantly reduced our drilling program. In 2011, we had 22 operated rigs in the Haynesville/Bossier shale play at our peak. We began to reduce our rig count in late 2011 and currently have three operated rigs drilling in the play. We will continue to assess product pricing and project economics to make further decisions on rig count. Our development drilling program for 2012 focused in DeSoto Parish, Louisiana where we continued our 80-acre spacing manufacturing program. We currently have 34 units fully developed in the Haynesville in DeSoto Parish. During 2012, we drilled 58 gross (21.8 net) operated wells in the Haynesville/Bosser shale play. We drilled and completed 20 gross (5.9 net) operated Haynesville horizontal wells and participated in 1 gross (0.2 net) OBO Haynesville horizontal well during the fourth quarter 2012. We utilized an average of five operated rigs and spud 10 operated horizontal wells during the quarter. We currently have no OBO rigs drilling. In total, we have 378 operated horizontal wells and 178 OBO horizontal wells flowing to sales.
During 2013, we plan to drill 26 gross (15.5 net) operated wells with a three rig program. We plan to complete and turn to sales 42 gross wells (22.1 net), including completions carried into 2013 from wells drilled in late 2012.
The average initial production rate from our operated Haynesville horizontal wells completed in the fourth quarter 2012 in DeSoto Parish was 12.7 Mmcf per day with an average 7,550 psi flowing casing pressure on an average 18/64ths choke. This maximum choke size is indicative of our modified restricted choke management program in DeSoto Parish. We have completed 69 wells in 11 development units in 2012 in DeSoto Parish and all of the wells were managed with this modified choke program. Our well performance has been very consistent. The average initial production rate for all 71 wells completed in 2012 in DeSoto Parish was 12.7 Mmcf per day with an average 7,784 psi flowing casing pressure on an average 18/64ths choke.
Our cost reduction and efficiency program is delivering positive results. We continue to see improvements in drilling times, stimulation costs and overall capital efficiency. Our DeSoto Parish well costs in the fourth quarter 2011 averaged $9.5 million per well. With the changes implemented to date, our current estimated well cost in the DeSoto Parish area is $8.0 million, approximately $1.5 million or 16% less than actual costs at year end 2011. The largest factors in our cost reduction efforts to date are fracture stimulation market conditions, fracture stimulation design changes, modified tubing design and changes to the installation procedure, reduced drilling times and overall improved management of all rental items. We have realized significant improvements in lease operating cost efficiencies since year end 2011. From the fourth quarter 2011 to current, we have realized a 32% reduction in total direct lease operating costs. Our new restricted choke program has contributed to this reduction in operating expenses by reducing water production volumes and lowering our flowing gas temperatures. The repair and maintenance costs have been reduced by reallocating work schedules through company personnel and reducing third party services. Our operations control room in our Dallas headquarters plays a significant role in our well surveillance process. We have reduced our overall production downtime to approximately 4% through better coordination and scheduling of all aspects of our field activities. From this control room, we have the ability to continuously monitor and remotely control natural gas flow 24 hours per day, 365 days per year.
Cotton Valley, Hosston, Travis Peak, Pettet
Our conventional Cotton Valley, Hosston, Travis Peak and Pettet assets were contributed to the partnership with HGI on February 14, 2013. The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in this group of assets as its production averaged approximately 48 Mmcf per day of net natural gas volumes from the lower Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet for the month of Dec