EXCO Resources, Inc. Reports Fourth Quarter And Full Year 2012 Results

EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced fourth quarter and full year operating and financial results for 2012.
  • 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
Production:
Total production (Mmcfe) 189,928 (36,647 ) 9,345 162,626
Average production (Mmcfe/d) 519 (100 ) 26 445
Revenues:
Revenues, excluding derivatives $ 546,609 $ (159,447 ) $ 40,659 $ 427,821
Average realized price ($/Mcfe) 2.88 4.35 4.35 2.63
Expenses:
Direct operating costs 77,127 (46,824 ) 11,940 42,243
Per Mcfe 0.41 1.28 1.28 0.26
Production and ad valorem taxes 27,483 (18,956 ) 4,834 13,361
Per Mcfe 0.14 0.52 0.52 0.08
Gathering and transportation 102,875 (12,841 ) 3,275 93,309
Per Mcfe 0.54 0.35 0.35 0.57
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.”

Net income

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
Adjustments:
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.

Cash flow

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,
(in thousands) 2012 2011 2012 2011
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:
     
2012 Actuals
(in thousands) Fourth Quarter Full Year 2013 Budget
Capital expenditures:
Development capital $ 76,678 $ 403,342 $ 214,000
Gas gathering and water pipelines 39 1,044 1,000
Lease acquisitions and seismic (1) 37,925 47,025 17,000
Capitalized interest 5,317 23,809 25,000
Corporate and other   5,264   24,494   16,000
Total $ 125,223 $ 499,714 $ 273,000

(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.

Haynesville/Bossier Shale

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 December 2012. With current low commodity prices, the primary focus in the Vernon Field is to minimize our operating expense while maintaining production. We have successfully mitigated the production decline rate in the field over the last two years. We have additional acreage and production in Caddo and DeSoto Parishes, Louisiana, primarily in four fields-Holly, Kingston, Caspiana and Longwood. We also have acreage and production in Harrison, Panola, and Gregg Counties in Texas, primarily across three fields-Carthage, Waskom, and Danville. Production from these areas is primarily from Cotton Valley sands at depths ranging from 10,400 to 11,000 feet and the Travis Peak and Hosston Sands at 7,800 to 10,000 feet. Due to low commodity prices, we are not actively drilling in these formations. Capital spending will be focused on maintaining a strong emphasis on base production performance. We typically run multiple service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels. The partnership with HGI currently has 915 wells flowing to sales with a total gross operated production rate of approximately 124.1 Mmcfe per day (67.0 Mmcfe per day net). During the first quarter 2013, the partnership expects to close on the acquisition from BG Group of their shallow interests in the East Texas/North Louisiana JV area.

Marcellus Shale

Our gross Marcellus shale production as of December 31, 2012, was approximately 157 Mmcf per day (43.2 Mmcf per day net), which represents an increase of more than 73% since the end of 2011. As of December 31, 2012, we had more than 19.7 Mmcf per day (4.0 Mmcf per day net) of production shut in due primarily to offset drilling and completion activities. During 2012, we drilled and completed 38 gross (11.4 net) wells in our Marcellus area. We implemented a development program in Northeast Pennsylvania and an appraisal program in Central Pennsylvania. In West Lycoming and Central Pennsylvania, several of our most recent completions have averaged initial production rates in excess of 7.0 Mmcf per day, representing some of our best well performance to date. Most of our drilling activity during 2013 will be in Lycoming County, Pennsylvania where we are realizing some of our highest returns in the Marcellus shale. We are currently drilling with one operated rig due to low natural gas prices. During 2012, we realized significant cost reductions across operational functions with drilling costs down 46%, completion costs down 11% and operating costs down 39%. When natural gas prices recover, we plan to actively implement development drilling.

During the fourth quarter 2012, we spud 4 new operated wells and drilled and completed 13 gross (3.3 net) operated wells in the Marcellus shale. These 13 completed wells were all in Northeast Pennsylvania. During 2012, we also focused on building our field infrastructure, particularly water handling lines, storage and disposal facilities, in support of our expected future levels of activity.

Permian

We drilled and completed 10 gross (9.8 net) wells in our Sugg Ranch area during the fourth quarter 2012 with 90% drilling success. For the year, we drilled and completed 37 gross (36.1 net) wells with 95% drilling success. Economics for this drilling activity typically have rates-of-return in excess of 50%. In the fourth quarter, our production averaged approximately 3,900 barrels per day of net oil equivalents. This average production rate consisted of 1,450 net barrels of oil, 6,400 net Mcf of natural gas, and 1,340 net barrels of natural gas liquids per day. The shallow Permian assets were contributed to the partnership with HGI. The partnership expects to run one operated rig and drill and complete 36 gross (34.9 net) wells at Sugg Ranch in 2013.

Based on industry results surrounding our Permian acreage position, we are continuing to evaluate our shale potential. We have tested both the Wolfcamp and Cline shale formations vertically in several wells and continue to collect and analyze core samples. The Wolfcamp and Cline shale rights were not contributed to the partnership with HGI.

TGGT

Our jointly held midstream company, TGGT, had total throughput which averaged approximately 1.4 Bcf per day during the fourth quarter of 2012 and averaged approximately 1.5 Bcf per day for full year 2012. TGGT's adjusted EBITDA was $38 million for the fourth quarter of 2012 and $158 million for full year 2012, a 41% increase over adjusted EBITDA of $112 million for full year 2011.

TGGT's capital spending for the fourth quarter of 2012 was $18 million, while the full year 2012 spending totaled $126 million. TGGT expects its capital budget for 2013 will be approximately $40 million, which is primarily associated with field infrastructure pipelines to support drilling activity in North Louisiana and East Texas. The substantial reduction in capital expenditures in 2013 compared to 2012 reflects the completion of all major facility projects coupled with reduction in drilling activities.

Proved Reserves

Our estimated proved reserves as of December 31, 2012, were 1.0 Tcfe with a pre-tax PV-10 of $696 million calculated pursuant to SEC pricing rules. For 2012, the reference price was $2.76 per Mmbtu for natural gas and $94.71 per Bbl for oil which resulted in an adjusted price of $2.54 per Mcf for natural gas and $89.84 per Bbl for oil. For 2012, we began separately reporting NGL reserves. The average price of NGL used in our Proved Reserves computation was $46.57 per barrel and was computed using the average realized price for NGL during the year. Using the average of the ten year futures strip price at December 31, 2012, as adjusted for energy content, quality and basis differentials, of $4.45 per Mcf for natural gas and $82.58 per Bbl of oil, our estimated Proved Reserves would have been 1.6 Tcfe with a pre-tax PV-10 of $1.8 billion.

During 2012, we added 102 Bcfe of Proved Reserves through the drill bit and produced 190 Bcfe. The impact of price declines for natural gas during 2012 resulted in downward revisions to Proved Reserves of 467 Bcfe while performance related revisions increased our Proved Reserves by 246 Bcfe. In addition, the impact of low natural gas prices resulted in reclassification of Proved Reserves to unproved reserves totaling 9 Bcfe as the projects did not meet the five year drilling schedule required by SEC rules. Positive reserve revisions were taken in our Haynesville shale and reflected upward adjustments to production curves arising from more historical data to confirm type curves and lower drilling and completion costs. The following table presents the details of our changes in proved reserves:
       

 

 

Natural gas liquids

Equivalent natural
Oil (Mbbls)

Natural gas (Mmcf)

(Mbbls)

gas (Mmcfe)
Proved Developed Reserves 4,371 917,326 4,784 972,256
Proved Undeveloped Reserves 1,199   18,806   1,855   37,130  
Total Proved Reserves 5,570   936,132   6,639   1,009,386  
 
The changes in reserves for the year are as follows:
January 1, 2012 6,354 1,291,464 1,329,588
Purchase of reserves in place
Discoveries and extensions 492 96,615 424 102,111
Revisions of previous estimates:
Reclassification to unproved reserves (1) (437 ) (6,114 ) (8,736 )
Changes in price (110 ) (466,238 ) (466,898 )
Other factors (26 ) 205,898 6,724 246,086
Sales of reserves in place (2,837 ) (2,837 )
Production (703 ) (182,656 ) (509 ) (189,928 )
December 31, 2012 5,570   936,132   6,639   1,009,386  

(1) Represents Proved Undeveloped Reserves reclassified to unproved pursuant to the five year development rule established by the SEC. This reclassification was a result of decisions not to commit development capital in the current commodity price environment. While these locations qualify as Proved Undeveloped Reserves as they directly offset a proved location, our planned capital programs do not support development at this time, resulting in the reclassification.

Most of our proved reserves in the Haynesville/Bossier shales are booked in our DeSoto Parish area. We believe that booking of proved reserves in the Shelby Area and in the Marcellus shale will follow the history of the development of DeSoto Parish. Over the last four years, we transitioned from exploration to testing and delineation and, ultimately, to development in DeSoto Parish. As such, we booked much of the area on a proved basis at year-end 2010. Our drilling activities during 2012 in the Haynesville/Bossier shales were dominated by drilling in the DeSoto Parish area, the vast majority of which resulted in converting proved undeveloped reserves into proved developed reserves. During 2012, we completed a significant spacing test in the Shelby Area to fully develop the Haynesville and Bossier shales across two units. EXCO and an offset operator drilled 14 new horizontal wells during 2011. These wells were completed and turned to sales in the first quarter 2012. We will continue to evaluate this spacing pilot before proceeding with additional development as natural gas prices improve. In Appalachia, our drilling activities in 2012 were focused on establishing a development program in Northeast Pennsylvania and continuing to appraise our Central Pennsylvania assets.

We believe that an analysis of our total proved finding and development costs, primarily for our shale operations, is most relevant on an inception to date basis, defined as January 1, 2009 through December 31, 2012, as yearly computations for development of proved undeveloped locations are subject to significant volatility due to timing of booking Proved Reserves when pad development operations are conducted. Our drilling and development spending totaled $1.8 billion from 2009 to 2012 resulting in a finding and development cost of $1.54 per Mcfe. Including revisions other than price, our inception to date finding and development cost was $1.33 per Mcfe. Including $397 million of proved property and leasehold acquisitions, our “all-in” finding and development cost was $1.51 per Mcfe. Adjusting for the benefit of $537 million of BG Group carries attributable to our joint ventures, our finding and development cost would have been $1.87 per Mcfe. As of December 31, 2012, the carrying value of our undeveloped leasehold costs associated with future proved reserve addition potential was $392 million. These undeveloped locations, which represent approximately 80,000 net undeveloped acres, are the result of several significant acquisitions in the Haynesville/Bossier and Marcellus shale resource plays in 2009 and 2010. The following table details the components of our inception to date finding and development costs:
 
2009 through 2012
(dollars in thousands, except per Mcfe) Cost   Mmcfe   Per Mcfe
Haynesville (1) $ 1,074,317 887,032 $ 1.21
Marcellus (2)   85,867 78,367   1.10
Total Shale 1,160,184 965,399 1.20
Conventional (3)   267,944 101,147   2.65
Total development 1,428,128 1,066,546 1.34
Exploratory (4)   408,678 124,386   3.29
Total development and exploration 1,836,806 1,190,932 1.54
Revisions - other than price   187,996  
Subtotal 1,836,806 1,378,928 1.33
Proved acquisitions 176,810 100,601 1.76
Leasehold additions   219,946  
Total $ 2,233,562 1,479,529 $ 1.51

(1) Adjusting for the cumulative benefit of $353 million of BG Group carry associated with our Haynesville development drilling, our inception to date finding and development cost would have been $1.61 per Mcfe.(2) Adjusting for the benefit of $63 million of BG Group carry associated with our Marcellus development drilling, our inception to date finding and development cost would have been $1.91 per Mcfe.(3) Primarily development of our Permian assets which have high oil and NGL production.(4) Adjusting for the cumulative benefit of $121 million of BG Group carries in Haynesville and Marcellus exploratory drilling, our inception to date finding and development cost would have been $4.26 per Mcfe.

During 2012, we added 207 Bcfe to our proved developed reserves resulting in a finding and development cost of $1.60 per Mcfe. Adjusting for the benefit of $49 million of BG Group carry associated with our proved developed reserve additions in 2012, our finding and development cost would have been $1.84 per Mcfe. The following table details the components of our 2012 proved developed additions:

     
2012
(dollars in thousands, except per Mcfe) Cost Mmcfe Per Mcfe
Haynesville $ 232,660 141,076 $ 1.65
Marcellus   62,008 51,334   1.21
Total Shale 294,668 192,410 1.53
Conventional   34,345 12,861   2.67
Total development 329,013 205,271 1.60
Exploratory   3,450 2,049   1.68
Total development and exploration (1) $ 332,463 207,320 $ 1.60

(1) Excludes $13 million of rig termination fees, $20 million of field operations capital and $38 million of fourth quarter leasehold and development costs which are not directly associated with future proved developed reserve additions.

Financial Data

Our consolidated balance sheets as of December 31, 2012 and December 31, 2011 and consolidated statements of operations for the three months and full year ended December 31, 2012 and 2011, and consolidated statements of cash flows for the year ended December 31, 2012 and 2011, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Thursday, February 21, 2013 at 9:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID#90683761. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted, after market close, on EXCO’s website on Wednesday, February 20, 2013.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., March 7, 2013. Please call (800) 585-8367 and enter conference ID#90683761 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this press release and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2011, and after February 21, 2013, our Annual Report on Form 10-K for the year ended December 31, 2012, and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. EXCO may use broader terms to describe additional reserve opportunities such as “potential,” “unproved,” or “unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, and after February 21, 2013, our Annual Report on Form 10-K for the year ended December 31, 2012, which is available on our website at www.excoresources.com under the Investor Relations tab.
   
 
EXCO Resources, Inc.
Consolidated balance sheets
 

December 31,

December 31,
(in thousands) 2012 2011
 
Assets
Current assets:
Cash and cash equivalents $ 45,644 $ 31,997
Restricted cash 70,085 155,925
Accounts receivable, net:
Oil and natural gas 84,348 88,518
Joint interest 69,446 170,918
Other 15,053 28,488
Inventory 5,705 8,345
Derivative financial instruments 49,500 164,002
Other   22,085     29,815  
Total current assets   361,866     678,008  
Equity investments 347,008 302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 470,043 667,342
Proved developed and undeveloped oil and natural gas properties 2,715,767 3,392,146
Accumulated depletion   (1,945,565 )   (1,657,165 )
Oil and natural gas properties, net   1,240,245     2,402,323  
Gas gathering assets 130,830 136,203
Accumulated depreciation and amortization   (34,364 )   (29,104 )
Gas gathering assets, net   96,466     107,099  
Office, field and other equipment, net 20,725 42,384
Deferred financing costs, net 22,584 29,622
Derivative financial instruments 16,554 11,034
Goodwill 218,256 218,256
Other assets   28     28  
Total assets $ 2,323,732   $ 3,791,587  
   
 
EXCO Resources, Inc.
Consolidated balance sheets
 

 

 

December 31,

December 31,
(in thousands, except per share and share data) 2012 2011
 
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities $ 83,240 $ 117,968
Revenues and royalties payable 134,066 148,926
Accrued interest payable 17,029 17,973
Current portion of asset retirement obligations 1,200 732
Income taxes payable
Derivative financial instruments   2,396     1,800  
Total current liabilities   237,931     287,399  
Long-term debt 1,848,972 1,887,828
Deferred income taxes
Derivative financial instruments 26,369
Asset retirement obligations and other long-term liabilities 61,067 58,028
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding
Common stock, $0.001 par value; 350,000,000 authorized shares; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011 215 215
Additional paid-in capital 3,200,067 3,181,063
Accumulated deficit (3,043,410 ) (1,615,467 )
Treasury stock, at cost; 539,221 shares at December 31, 2012 and December 31, 2011   (7,479 )   (7,479 )
Total shareholders’ equity   149,393     1,558,332  
Total liabilities and shareholders’ equity $ 2,323,732   $ 3,791,587  
       
 
EXCO Resources, Inc.
Consolidated statements of operations
 
Three Months Ended December 31, Years Ended December 31,
(in thousands, except per share data) 2012 2011 2012 2011
Revenues:
Oil and natural gas $ 152,162 $ 178,871 $ 546,609 $ 754,201
Costs and expenses:
Oil and natural gas operating costs 18,043 23,923 77,127 84,766
Production and ad valorem taxes 6,812 5,175 27,483 23,875
Gathering and transportation 24,692 27,812 102,875 86,881
Depletion, depreciation and amortization 55,648 109,123 303,156 362,956
Write-down of oil and natural gas properties 324,040 233,239 1,346,749 233,239
Accretion of discount on asset retirement obligations 991 924 3,887 3,652
General and administrative 21,624 28,183 83,818 104,618
(Gain) loss on divestitures and other operating items   7,683     (1,352 )   17,029     23,819  
Total costs and expenses   459,533     427,027     1,962,124     923,806  
Operating income (loss) (307,371 ) (248,156 ) (1,415,515 ) (169,605 )
Other income (expense):
Interest expense (18,424 ) (17,438 ) (73,492 ) (61,023 )
Gain on derivative financial instruments 47,787 88,752 66,133 219,730
Other income 380 233 969 788
Equity income   8,599     9,957     28,620     32,706  
Total other income (expense)   38,342     81,504     22,230     192,201  
Income (loss) before income taxes (269,029 ) (166,652 ) (1,393,285 ) 22,596
Income tax expense                
Net income (loss) $ (269,029 ) $ (166,652 ) $ (1,393,285 ) $ 22,596  
Earnings (loss) per common share:
Basic:
Net income (loss) $ (1.25 ) $ (0.78 ) $ (6.50 ) $ 0.11  
Weighted average common shares outstanding   214,672     214,137     214,321     213,908  
Diluted:
Net income (loss) $ (1.25 ) $ (0.78 ) $ (6.50 ) $ 0.10  
Weighted average common and common equivalent shares outstanding   214,672     214,137     214,321     216,705  
   
 
EXCO Resources, Inc.
Consolidated statements of cash flows
 
Years Ended December 31,
(in thousands) 2012 2011
Operating Activities:
Net income (loss) $ (1,393,285 ) $ 22,596
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 303,156 362,956
Share-based compensation expense 8,926 11,012
Accretion of discount on asset retirement obligations 3,887 3,652
Write-down of oil and natural gas properties and other impairment losses on long-lived assets 1,346,749 240,039
Income from equity investments (28,620 ) (32,706 )
Non-cash change in fair value of derivatives 135,945 (84,313 )
Deferred income taxes
Amortization of deferred financing costs and discount on the 2018 Notes 9,788 9,759
(Gain) loss on divestitures and sale of other assets 1,303 (479 )
Effect of changes in:
Accounts receivable 112,919 (79,359 )
Other current assets 7,090 (5,961 )
Accounts payable and other current liabilities   6,928     (18,653 )
Net cash provided by operating activities   514,786     428,543  
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment (534,175 ) (984,085 )
Property acquisitions (2,748 ) (753,286 )
Equity method investments (14,907 ) (13,829 )
Proceeds from disposition of property and equipment 38,045 449,683
Restricted cash 85,840 5,792
Net changes in advances (to) from Appalachia JV 851 (1,707 )
Distributions from equity method investments 125,000
Deposit on acquisitions 464,151
Other       (1,250 )
Net cash used in investing activities   (427,094 )   (709,531 )
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement 53,000 706,000
Repayments under the EXCO Resources Credit Agreement (93,000 ) (407,500 )
Proceeds from issuance of common stock 1,968 12,063
Payment of common stock dividends (34,358 ) (34,238 )
Deferred financing costs and other   (1,655 )   (7,569 )
Net cash provided by (used in) financing activities   (74,045 )   268,756  
Net increase (decrease) in cash 13,647 (12,232 )
Cash at beginning of period   31,997     44,229  
Cash at end of period $ 45,644   $ 31,997  
 
Supplemental Cash Flow Information:
Cash interest payments $ 86,298   $ 78,125  
Income tax payments $   $ 1,458  
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation $ 7,513   $ 6,406  
Capitalized interest $ 23,809   $ 30,083  
Issuance of common stock for director services $ 597   $ 70  
Accrued restricted stock dividends $ 300   $ 129  
       
 

EXCO Resources, Inc.

Consolidated EBITDA

And Adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2012 2011 2012 2011
Net income (loss) $ (269,029 ) $ (166,652 ) $ (1,393,285 ) $ 22,596
Interest expense 18,424 17,438 73,492 61,023
Income tax expense
Depreciation, depletion and amortization   55,648     109,123     303,156     362,956  
EBITDA(1) (194,957 ) (40,091 ) (1,016,637 ) 446,575
Accretion of discount on asset retirement obligations 991 924 3,887 3,652
Non-cash write down of oil and natural gas properties 324,040 233,239 1,346,749 233,239
Non-recurring other operating items 8,200 118 17,928 27,660
Equity income (8,599 ) (9,957 ) (28,620 ) (32,706 )
Non-cash change in fair value of derivative financial instruments (8,394 ) (36,425 ) 135,945 (84,313 )
Share based compensation expense   854     3,475     8,926     11,012  
Adjusted EBITDA (1) $ 122,135 $ 151,283 $ 468,178 $ 605,119
Interest expense (18,424 ) (17,438 ) (73,492 ) (61,023 )
Income tax expense
Amortization of deferred financing costs and discount on the 2018 Notes 1,677 3,441 9,788 9,759
Non-recurring other operating items (8,000 ) 474 (16,625 ) (21,339 )
Changes in working capital   2,621     (64,551 )   126,937     (103,973 )
Net cash provided by operating activities $ 100,009   $ 73,209   $ 514,786   $ 428,543  
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2012 2011 2012 2011
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities $ 100,009 $ 73,209 $ 514,786 $ 428,543
Investing activities (119,841 ) (263,129 ) (427,094 ) (709,531 )
Financing activities (8,077 ) 165,499 (74,045 ) 268,756
Other financial and operating data:
EBITDA(1) (194,957 ) (40,091 ) (1,016,637 ) 446,575
Adjusted EBITDA(1) 122,135 151,283 468,178 605,119

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash write-downs of assets, stock-based compensation and income or losses from equity method investments. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our credit agreement and the indenture governing our 7.5% senior notes due September 15, 2018. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.
       
 
TGGT Holdings, LLC
EBITDA and Adjusted EBITDA reconciliation
(Unaudited)
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2012 2011 2012 2011
 
Equity income (loss) $ 8,599 $ 9,957 $ 28,620 $ 32,706
Amortization of the difference in the historical basis of our contribution to TGGT (399 ) (399 ) (1,605 ) (1,605 )
Equity (gain) loss of other investments   (980 )   457     305     513  
EXCO's share of TGGT net income 7,220 10,015 27,320 31,614
BG Group's share of TGGT net income   7,220     10,015     27,320     31,614  
TGGT net income 14,440 20,030 54,640 63,228
Interest expense 4,295 2,607 16,208 8,776
Margin tax expense 126 (482 ) 426 636
Depreciation and amortization   8,342     6,452     32,132     25,453  
TGGT EBITDA(1) 27,203 28,607 103,406 98,093
Asset impairments and non-recurring other operating items   10,810     674     54,175     13,967  
TGGT Adjusted EBITDA(1) $ 38,013   $ 29,281   $ 157,581   $ 112,060  
EXCO's share of TGGT Adjusted EBITDA (2) $ 19,007   $ 14,641   $ 78,791   $ 56,030  

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude asset impairments, gains and losses on divestitures and non-recurring other operating items. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.(2) Represents our 50% equity share in TGGT.
       
 
TGGT Holdings, LLC
Computation of adjusted net income
(Unaudited)
 
Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2012 2011 2012 2011
Net income, GAAP $ 14,440 $ 20,030 $ 54,640 $ 63,228
Adjustments:
Loss on asset disposal 164 1,640 1,579
Asset impairment, net of insurance recoveries 10,810 510 50,771 9,688
Other non-cash items       1,764   2,700
Total adjustments   10,810   674   54,175   13,967
Adjusted net income $ 25,250 $ 20,704 $ 108,815 $ 77,195
 
EXCO's 50% share of TGGT's adjusted net income (1) $ 12,625 $ 10,352 $ 54,408 $ 38,598

(1) TGGT’s net income, computed in accordance with GAAP, includes certain items not typically included by securities analysts in published estimates of financial results. This table provides a reconciliation of GAAP net income to a non-GAAP measure of adjusted net income.
           
 
EXCO Resources, Inc.
Summary of operating data
 
Three Months Ended Years Ended
December 31, % December 31, %
  2012 2011 Change 2012 2011 Change
Production:
Oil (Mbbls) 160 188 (15 )% 704 741 (5 )%
Natural gas liquids (Mbbls) 128 126 2 % 510 505 1 %
Natural gas (Mmcf) 42,160 49,305 (14 )% 182,644 176,700 3 %
Total production (Mmcfe) (1) 43,888 51,189 (14 )% 189,928 184,176 3 %
Average daily production (Mmcfe) 477 556 (14 )% 519 505 3 %
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl) $ 81.13 $ 89.48 (9 )% $ 88.24 $ 91.01 (3 )%
Natural gas liquids (per Bbl) 41.96 60.96 (31 )% 43.27 58.69 (26 )%
Natural gas (per Mcf) 3.17 3.13 1 % 2.53 3.72 (32 )%
Natural gas equivalent (per Mcfe) 3.47 3.49 (1 )% 2.88 4.10 (30 )%
Costs and expenses (per Mcfe):
Oil and natural gas operating costs $ 0.41 $ 0.47 (13 )% $ 0.41 $ 0.46 (11 )%
Production and ad valorem taxes 0.16 0.10 60 % 0.14 0.13 8 %
Gathering and transportation 0.56 0.54 4 % 0.54 0.47 15 %
Depletion 1.19 2.05 (42 )% 1.52 1.87 (19 )%
Depreciation and amortization 0.08 0.08 0.08 0.10 (20 )%
General and administrative 0.49 0.55 (11 )% 0.44 0.57 (23 )%

(1) Effective with the second quarter 2012, we began reporting NGL volumes separately and have recast prior period volumes to conform to current period reporting.

Copyright Business Wire 2010

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