EXCO Resources, Inc. Reports First Quarter 2013 Results
EXCO Resources, Inc. Reports First Quarter2013 Results
DALLAS--(BUSINESS WIRE)-- EXCO Resources, Inc. (NYS: XCO) ("EXCO") today announced first quarter results for 2013.
Adjusted net income, a non-GAAP measure adjusting for gains from asset sales, non-cash gains or losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and other items typically not included by securities analysts in published estimates, was $0.13 per diluted share for the first quarter 2013 compared to $0.03 per diluted share for the first quarter 2012.
Adjusted earnings before interest, taxes, depreciation, depletion and amortization, gains on asset sales, ceiling test write-downs and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the first quarter 2013 were $96 million compared with $111 million in the first quarter 2012.
GAAP results were net income of $158 million, or $0.74 per diluted share, for the first quarter 2013 compared with a net loss of $282 million, or $1.32 per diluted share, for the first quarter 2012. The first quarter 2013 includes a $187 million gain from the contribution of 74.5% of our interests in certain conventional properties to our partnership with Harbinger Group Inc. (HGI). The first quarter 2012 net loss was primarily due to a $276 million non-cash ceiling test write-down of oil and natural gas properties.
Oil, natural gas and natural gas liquids (NGL) production was 41 Bcfe, or 452 Mmcfe per day, for the first quarter 2013 compared with 49 Bcfe, or 537 Mmcfe per day in the first quarter 2012. The decreases in production reflect the impact of the properties contributed to the partnership with HGI and our reduced drilling program initiated in 2012. First quarter 2013 production from our Haynesville/Bossier shale was 337 Mmcf per day compared with 390 Mmcf per day in the first quarter 2012. First quarter 2013 production in our Appalachia region was 56 Mmcfe per day, a 37% increase from the first quarter 2012. The increase reflects drilling in the Marcellus shale and completion activities which resulted in 41 additional wells coming on-line subsequent to first quarter 2012.
Oil, natural gas and NGL revenues, before cash settlements on derivatives, for the first quarter 2013 were $138 million compared with first quarter 2012 revenues of $135 million. Our average sales price per Mcfe increased to $3.40 per Mcfe for the first quarter 2013 from $2.76 per Mcfe for the first quarter 2012. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $155 million for the first quarter 2013, compared with $185 million in the first quarter 2012.
Our direct operating costs were $0.33 per Mcfe for the first quarter 2013 compared with $0.47 per Mcfe for the first quarter 2012. We continue taking significant steps in reducing our operating costs in all operating areas. In addition, our first quarter 2013 operating costs per Mcfe were favorably impacted by the contribution of certain conventional properties to the partnership with HGI. The conventional assets have higher operating costs than our horizontal wells.
TGGT's average throughput was approximately 1.4 Bcf per day during the first quarter 2013, compared with 1.5 Bcf per day during the fourth quarter 2012 and 1.5 Bcf per day in the first quarter 2012. Our 50% share of TGGT's adjusted EBITDA in the first quarter 2013 was $18 million compared with $17 million in the first quarter 2012.
On February 14, 2013, we formed a partnership with HGI. 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 of West Texas to the partnership in exchange for net proceeds of $573 million, after customary preliminary purchase price adjustments and a 25.5% economic interest in the partnership. HGI's economic interest in the partnership is 74.5%. We report our 25.5% interest in the partnership using proportional consolidation. The primary strategy of the partnership is to acquire conventional producing oil and natural gas properties to enhance asset value and cash flow. Immediately following the closing, the partnership entered into an agreement to purchase certain shallow conventional assets from BG Group, plc (BG Group) for $131 million, after customary preliminary purchase price adjustments. This acquisition represented incremental working interest in properties operated by the partnership. The following table presents selected pro forma operating and financial information for the three months ended March 31, 2013 and 2012 as if these transactions occurred on January 1, 2012:
Three months ended March 31, 2013 | Three months ended March 31, 2012 | ||||||||||||||||||||||||||
(dollars in thousands, except per unit rate) | Historical | Pro forma | Pro forma | Historical | Pro forma | Pro forma | |||||||||||||||||||||
Production: | |||||||||||||||||||||||||||
Total production (Mmcfe) | 40,697 | (2,705 | ) | 37,992 | 48,876 | (6,606 | ) | 42,270 | |||||||||||||||||||
Average production (Mmcfe/d) | 452 | (30 | ) | 422 | 537 | (73 | ) | 464 | |||||||||||||||||||
Revenues: | |||||||||||||||||||||||||||
Revenues, excluding derivatives | $ | 138,223 | $ | (12,657 | ) | $ | 125,566 | $ | 134,848 | $ | (30,758 | ) | $ | 104,090 | |||||||||||||
Average realized price ($/Mcfe) | 3.40 | 4.68 | 3.31 | 2.76 | 4.66 | 2.46 | |||||||||||||||||||||
Expenses: | |||||||||||||||||||||||||||
Direct operating costs | $ | 13,617 | $ | (3,489 | ) | $ | 10,128 | $ | 22,796 | $ | (8,420 | ) | $ | 14,376 | |||||||||||||
Per Mcfe | 0.33 | 1.29 | 0.27 | 0.47 | 1.27 | 0.34 | |||||||||||||||||||||
Production and ad valorem taxes | 5,248 | (1,545 | ) | 3,703 | 7,193 | (3,531 | ) | 3,662 | |||||||||||||||||||
Per Mcfe | 0.13 | 0.57 | 0.10 | 0.15 | 0.53 | 0.09 | |||||||||||||||||||||
Gathering and transportation | 24,476 | (782 | ) | 23,694 | 26,423 | (2,502 | ) | 23,921 | |||||||||||||||||||
Per Mcfe | 0.60 | 0.29 | 0.62 | 0.54 | 0.38 | 0.57 | |||||||||||||||||||||
Excess of revenues over operating expenses | $ | 94,882 | $ | (6,841 | ) | $ | 88,041 | $ | 78,436 | $ | (16,305 | ) | $ | 62,131 | |||||||||||||
(1) | The 2013 pro forma adjustments reflect the contribution of our interest in certain properties from January 1, 2013 to February 14, 2013 and the acquisition of certain shallow conventional assets from BG Group from January 1, 2013 to March 31, 2013. The 2012 pro forma adjustments reflect the impact of these transactions from January 1, 2012 to March 31, 2012. | |
We improved our liquidity by using the proceeds received upon formation of the partnership with HGI to reduce outstanding borrowings under our credit agreement. As a result of this transaction, our borrowing base under our credit agreement was reduced to $900 million. In addition, we utilized cash flows from operations and other divestitures to reduce outstanding borrowings under our credit agreement by an additional $40 million during the three months ended March 31, 2013.
Douglas H. Miller, EXCO's Chief Executive Officer, commented, "We are pleased with the positive financial results achieved in the first quarter through a continued focus on reducing expenses. Our operations team also continues to make drilling cost reductions in the Haynesville and Marcellus, and we are encouraged by the recent increase in natural gas prices.
"The Harbinger partnership transaction completed in February establishes a strong partnership that will enhance the long term value of EXCO while giving us flexibility and liquidity in the short term. We are excited to work with Harbinger Group Inc. to make strategic acquisitions to grow and develop this partnership.
"With our new senior leadership team in place, we will continue to actively evaluate acquisition opportunities and develop our properties within cash flow to grow the value of the Company. Regardless of commodity prices in 2013, we expect to continue to preserve liquidity, focus on cost controls and deliver stable cash flows."
Adjusted 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 | |||||||||||||||||||||
March 31, 2013 | March 31, 2012 | ||||||||||||||||||||
(in thousands, except per share amounts) | Amount | Per share | Amount | Per share | |||||||||||||||||
Net income (loss), GAAP | $ | 158,120 | $ | (281,649 | ) | ||||||||||||||||
Adjustments: | |||||||||||||||||||||
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes | 60,232 | (3,720 | ) | ||||||||||||||||||
Non-cash write down of oil and natural gas properties, before taxes | 10,707 | 275,864 | |||||||||||||||||||
Adjustments included in equity (income) loss | (286 | ) | 18,799 | ||||||||||||||||||
(Gain) loss on divestitures and other operating items | (184,386 | ) | 1,952 | ||||||||||||||||||
Deferred finance cost amortization acceleration | 3,535 | — | |||||||||||||||||||
Income taxes on above adjustments (1) | 44,079 | (117,158 | ) | ||||||||||||||||||
Adjustment to deferred tax asset valuation allowance (2) | (63,248 | ) | 112,660 | ||||||||||||||||||
Total adjustments, net of taxes | (129,367 | ) | 288,397 | ||||||||||||||||||
Adjusted net income | $ | 28,753 | $ | 6,748 | |||||||||||||||||
Net income (loss), GAAP (3) | $ | 158,120 | $ | 0.74 | $ | (281,649 | ) | $ | (1.32 | ) | |||||||||||
Adjustments shown above (3) | (129,367 | ) | (0.60 | ) | 288,397 | 1.35 | |||||||||||||||
Dilution attributable to share-based payments (4) | — | (0.01 | ) | — | — | ||||||||||||||||
Adjusted net income | $ | 28,753 | $ | 0.13 | $ | 6,748 | $ | 0.03 | |||||||||||||
Common stock and equivalents used for earnings per share (EPS): | |||||||||||||||||||||
Weighted average common shares outstanding | 214,784 | 214,145 | |||||||||||||||||||
Dilutive stock options | 5 | 451 | |||||||||||||||||||
Dilutive restricted shares | 72 | — | |||||||||||||||||||
Shares used to compute diluted EPS for adjusted net income | 214,861 | 214,596 | |||||||||||||||||||
(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 share equivalents from in-the-money stock options and dilutive restricted shares calculated in accordance with the treasury stock method. | |
Cash flow
Our cash flow from operations before changes in working capital was $81 million for the first quarter 2013. 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 | |||||||||
March 31, | |||||||||
(in thousands) | 2013 | 2012 | |||||||
Cash flow from operations, GAAP | $ | 43,214 | $ | 145,123 | |||||
Net change in working capital | 34,990 | (51,579 | ) | ||||||
Non-recurring other operating items | 2,652 | 1,952 | |||||||
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1) | $ | 80,856 | $ | 95,496 | |||||
(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. Cash flow from operations before changes in working capital 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 $59 million on development and exploitation activities, drilling and completing 28 gross (14.2 net) operated wells in the first quarter 2013. In addition, we participated in 2 gross (0.1 net) wells operated by others (OBO) during the first quarter 2013. We had an overall drilling success rate of 100% for the first quarter 2013. We spent $77 million on development and exploitation activities, drilling and completing 43 gross (18.9 net) operated wells in the fourth quarter 2012. In addition, we participated in 1 gross (0.2 net) well operated by others (OBO) during the fourth quarter 2012.
Our actual capital expenditures for the first quarter 2013 and our full year 2013 capital budget are presented in the following table:
(in thousands) | Three Months Ended | April - December 2013 | Full Year 2013 | |||||||||
Capital expenditures (1): | ||||||||||||
Development capital | $ | 58,715 | $ | 161,285 | $ | 220,000 | ||||||
Gas gathering and water pipelines | — | — | — | |||||||||
Lease acquisitions and seismic | — | 14,000 | 14,000 | |||||||||
Capitalized interest | 5,038 | 9,962 | 15,000 | |||||||||
Corporate and other | 4,596 | 19,404 | 24,000 | |||||||||
Total | $ | 68,349 | $ | 204,651 | $ | 273,000 | ||||||
(1) | Excludes capital expenditures related to our partnership with HGI. | |
Our 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 is a significant asset for EXCO and continues to yield strong results. At the end of the first quarter 2013, our Haynesville/Bossier shale operated production was 1,067 Mmcf per day gross (316 Mmcf per day net) and with the addition of production from our OBO wells, we had 338 Mmcf per day of total net Haynesville/Bossier shale production. We currently have three operated rigs drilling in the play. While our current plan is to maintain three rigs through 2013, we will continue to assess product pricing and project economics to make further decisions on our drilling activity. Our development drilling program for the first quarter 2013 was focused in DeSoto Parish, Louisiana where we continued our 80-acre spacing manufacturing program. We currently have 37 units fully developed in the Haynesville in DeSoto Parish. We completed and turned to sales 19 gross (7.8 net) operated Haynesville horizontal wells in the quarter. We utilized an average of three operated rigs and spud eight operated horizontal wells during the quarter. We participated in two OBO wells during the quarter and currently have one OBO rig drilling. In total, we have 396 operated horizontal wells and 179 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 a total of 42 gross wells (22.1 net), including completions carried into 2013 from wells drilled in late 2012.
The average initial production rate from the 19 operated Haynesville horizontal wells completed and turned to sales in the first quarter 2013 in DeSoto Parish was 13.7 Mmcf per day with an average 7,811 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.
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 current DeSoto Parish well costs are averaging approximately $7.8 million per well. The largest factors in our cost reduction efforts to date are fracture stimulation market conditions, fracture stimulation design changes, modified tubing program, reduced drilling times and overall improved management of all rental items. Our operations control room in our Dallas headquarters plays a significant role in our well surveillance and gas scheduling process. We have reduced our overall production downtime in the Haynesville to approximately 4.9% through better coordination and scheduling in 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.
Marcellus Shale
Our gross operated Marcellus shale production at the end of the first quarter 2013 was 181 Mmcf per day (48.3 Mmcf per day net). This represents a 15% increase since year end 2012. Our focus through 2013 is to complete and turn to sales our remaining drilled well inventory while reducing the size of our appraisal drilling program due to low product pricing. In the first quarter 2013, we spud one Marcellus appraisal well in Northeast Pennsylvania and completed five gross operated (2.5 net) Marcellus wells in Central and Northeast Pennsylvania. We turned to sales eight Marcellus wells in late 2012 in West Lycoming County Pennsylvania that resulted in some of our highest well performances to date as the IP rates ranged from 7.1 to 11.8 Mmcf per day with an average of 8.9 Mmcf per day per well. During the remainder of 2013, we plan to turn to sales an additional 13 Marcellus wells (nine in our Central Pennsylvania area and four in the East Lycoming County area). Our development planning for 2014 is underway and will be a combination of development drilling in our highest rate of return areas and selective appraisal drilling to delineate more of our acreage base.
In addition to the Marcellus shale production in Appalachia, we averaged 32 gross (13.2 net) operated Mmcf per day of conventional production in the region.
Partnership with HGI
The following discussion of operating results, capital expenditures and planned operations addresses our partnership with HGI. We contributed the conventional Permian and East Texas/North Louisiana assets to the partnership with HGI on February 14, 2013. On March 5, 2013 the partnership acquired additional oil and natural gas assets, including and above the Cotton Valley formation in the Danville, Waskom, and Holly fields in East Texas and North Louisiana from an affiliate of BG Group. The capital budget for the partnership with HGI for 2013 is approximately $40.0 million, which is primarily focused on development of its Permian Basin assets in West Texas and recompletion projects in North Louisiana.
Permian
During the first quarter 2013, 8 gross (7.8 net) wells were drilled and completed in the Sugg Ranch area with 100% drilling success. Economics for this drilling activity typically have high rates-of-return driven by oil and NGL content. The partnership with HGI expects to run one operated rig and drill and complete 36 gross (34.9 net) wells at Sugg Ranch in 2013. At the end of the first quarter 2013, production from the 445 partnership wells averaged approximately 3,700 barrels per day of net oil equivalents. This average production rate consisted of 1,360 net barrels of oil, 6,000 net Mcf of natural gas, and 1,330 net barrels of natural gas liquids per day.
East Texas/North Louisiana
The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in this group of assets. At the end of the first quarter 2013, production from the operated partnership wells averaged approximately 45 Mmcfe per day of net natural gas from the lower Cotton Valley and Bossier Sand formations. With current low commodity prices, the primary focus in the Vernon Field is to minimize operating expense while maintaining production.
The partnership with HGI has additional acreage and production in Caddo and DeSoto Parishes, Louisiana, primarily in four fields - Holly, Kingston, Caspiana and Longwood. In addition, the partnership with HGI has 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, Travis Peak and Hosston sands. At the end of the first quarter 2013, production from the operated partnership wells in these fields averaged approximately 37 Mmcfe per day of net natural gas. Due to low commodity prices, the partnership with HGI is not actively drilling in these fields. Capital spending during the first quarter 2013 was focused on maintaining a strong emphasis on base production performance. The partnership typically runs multiple service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels. During the remainder of the year, the partnership will initiate recompletions in 9 wells in the Holly field targeting Cotton Valley and Hosston sands. In East Texas/North Louisiana, the partnership with HGI currently has 906 wells flowing to sales with a total gross operated production rate of approximately 119 Mmcfe per day (82 Mmcfe per day net).
TGGT
Our jointly held midstream company, TGGT, had total throughput which averaged approximately 1.4 Bcf per day during the first quarter of 2013. TGGT's adjusted EBITDA was $37 million for the first quarter of 2013, which was a 6% increase over TGGT's adjusted EBITDA of $35 million for the first quarter of 2012. Through an effective asset optimization program, TGGT continues to significantly reduce its operating expenses, which were 21% less in the first quarter of 2013 than the fourth quarter of 2012.
TGGT's capital spending for the first quarter of 2013 was $7 million, which was 61% lower than the $18 million
