|Shares Out. (in M):||217||P/E||16.9x||13.8x|
|Market Cap (in $M):||3,601||P/FCF||-12.0x||830.5x|
|Net Debt (in $M):||888||EBIT||222||375|
EXCO Resources, Inc. (XCO)
Target Price (NAV): $30.38
Current Price: $16.61 (54% of Equity NAV)
Recommendation—Long XCO against the industry (EPX Index) or stock-specific shorts CHK (or CHK CDS), UPL
1) EXCO’s 6.0 Tcfe of risked resource potential captured within its current acreage represents nearly five times its 1.224 Tcfe of pro forma proved reserves, and this estimate is considerably below the company’s estimates of 8.6-14.2 Tcfe of resource potential. This resource upside should result in production growth at a greater than 30% CAGR between 2009 and 2014, and its 1.224 Tcfe of pro forma current proved reserves should grow to around 5.5 Tcfe, a 35% CAGR 2009-2014 using fairly conservative assumptions. The company’s operating performance, reserve and production growth outlook, and balance sheet have improved markedly with the restructuring of its resource base including $1.3B of JV proceeds, an additional >$1B of non-core asset divestitures, and the resulting repayment of $2B of debt year-to-date. EXCO is now a focused, predominantly natural gas resource play with 44,000+ net acres in the core of the Haynesville shale as well as 226,000 net acres in the fairway/core of the Marcellus that will serve as the growth engines of the company. With leverage to the two most prolific and likely low-cost shale plays in the United States, EXCO’s production and reserve growth potential mean that EXCO should be one of the fastest growing companies in the E&P industry at favorable economics. Importantly, EXCO should be able to develop its substantial resource potential with a combination of internally generated cash flow as well as availability under existing credit lines—it currently has $734mm of unused borrowing capacity and $111mm of cash for a total of $845mm of liquidity on a pro forma basis. This compares to its estimated 2010 capital expenditures of $470mm (net of the $240mm of carry it will get from its JV with BG Group to develop the Haynesville).
2) EXCO is currently trading at ~55% of my equity NAV appraisal (60% of enterprise NAV) using an 8% discount rate and the current NYMEX strips for natural gas ($5.23/mmbtu, $6.18, $6.45, $6.63, $6.83, and $7.02 for ’10-’15, respectively) and crude oil ($74.04/bbl, $84.07, $86.06, $87.73, $89.52, and $91.89 for ’10-’15, respectively). This compares favorably to the group that is trading at an average of 71% of equity NAV (74% of Enterprise NAV) using the same underlying assumptions. On a NAV basis, EXCO trades at a ~15% discount to the industry despite its superior production and reserve growth profile. Importantly, EXCO’s hard asset value consisting of proved reserves of 1.224 Tcfe (pro forma for recent divestitures) plus the value of its midstream assets and the present value of its hedge book is $14.91/share; less pro forma Net Debt of $888.7mm or $4.09/share, the net asset value of EXCO’s hard assets is $10.81/share which represents 66% of the current stock price. This would imply that only $5.67/share or 29% of XCO’s $19.57/share of risked resource potential is currently being valued by the market.
3) EXCO’s 50%-50% joint venture (announced 6/09, closed 8/09) with BG Group (BG LN) from which EXCO received ~$1.3B from BG for joint development of EXCO’s core Haynesville shale position is likely the prelude to a similar value-unlocking partnership that will develop EXCO’s Marcellus acreage. Longer term, if BG’s past practice is any indication of it s intentions with EXCO, BG could ultimately acquire XCO. In April of 2008, BG entered into a similar partnership with Queensland Gas in Australia in order to develop coal seam natural gas to support the partnership’s Gladstone LNG plant. October 28, 2008, BG announced that it was acquiring Queensland Gas for $3.4B, an 80% premium to the prior close.
4) EXCO’s equity-friendly strategy differentiates it from its E&P peers, and it is a characteristic that appears to be underappreciated by the market. Unlike other resource-heavy companies that are serial acquirers or issuers of equity with the purpose of drilling and amassing resource potential, XCO stockholders should reap the benefits as it divests non-core resources in order to develop and optimize the value of its Haynesville and Marcellus acreage. ~33.8% of its equity is owned by directors (including its largest investors) and named executive officers. These include CEO Doug Miller (4.6mm shares or 2.2% of shares outstanding), Jim Ford of Oaktree Capital Management (34.8mm shares or 16.4% of shares outstanding), Jeff Serota of Ares Capital Management (12.9mm shares or 6.1% of shares outstanding), Boone Pickens of BP Capital (10.7mm shares or 5.0% of shares outstanding) and Jeff Benjamin of Cyrus Capital Partners (6.5mm shares, or 3.1% of shares outstanding), each of whom hold board seats and appear to be steering management in the right direction in terms of creating value for equity holders. This is a clear point of differentiation when compared to most other exploration and production companies that tend to be poor allocators of capital through the cycle. Many competitors used leverage and share issuances in the recent past to make questionable acquisitions, asset purchases, and in order to lease land expected to contain oil and gas resources—most at peak valuations. Further, many of the other resource plays like Petrohawk (HK) and Chesapeake (CHK) appear to require either future dilutive equity issuances or substantially higher cash flow resulting from higher commodity prices in order to fund aggressive capital expenditure plans for 2010 and 2011. In both of those cases, aggressive capital plans are required in order to merely hold acreage accumulated during 2008 and 2009. EXCO has 71% of its core Haynesville acreage “held” by production and 70% of its Marcellus acreage “held.”
5) XCO is conservatively hedged going into 2010 given the continued depressed pricing environment as the result of both oversupply and depressed demand. Based on the initial 2010 production guidance provided at its recent analyst day (290-340mmcfe/d), 64% of total expected 2010 production is hedged at a weighted-average price of $8.84/mcfe. Longer-term, EXCO maintains its leverage to natural gas prices with only 10% of it’s expected 2011 production (initial guidance 490-565mmcfe/d) hedged at $11.34/mcfe. The current PV of EXCO’s hedges using the futures strip is $315.6mm, or $1.46/share.
Investment Risks/Bear Case
Key Risks/Events That Could Change Thesis:
Environmental issues could arise (for instance, those involving the disposal of water and fluids used in fracturing) in one or both of its key shale plays, the Haynesville and Marcellus, thus changing the resource potential and/or the economics of the plays. The flip side is that the domestic supply of natural gas will be increasingly dependent on unconventional gas resources--including shale gas--going forward such that if shale gas operations were to be impaired, the supply of natural gas would become severely strained and prices would likely increase materially.
Play Risk--EXCO’s two key plays, the Haynesville and Marcellus Shales, are still emerging plays such that there are still a great many unknowns (for instance, how will actual well results compare to estimated ultimate recovery forecasts, etc.) and as a result there are substantial risks associated with operations in both of these plays as well as economic risks that the early well results will not be sustainable or representative of the entire play. If one of the plays were deemed uneconomical, the value of EXCO would likely be impaired.
Macro Risk—The energy industry is subject to numerous global economic risks. EXCO is more leveraged to natural gas and therefore the value is more affected by changes in natural gas prices and volumes, with prices being the most volatile piece of that equation. Natural gas prices are seasonal, and usually strongest in the peak summer and winter months. Weather is a risk in that warmer/cooler weather means more/less gas will be used during the peak demand months, and can cause variability in the supply and demand balance. The three key concerns on the macro side for natural gas are probably:
-A large influx of LNG would likely upset the supply and demand balance such that prices would probably be impaired. While currently only about ~1 Bcf/d of LNG is being dispatched out of a total domestic supply of ~58-60 Bcf/d, there are very large LNG projects starting up now and in 2010-2012 that could cause an increase in the LNG that is dispatched in the U.S.
-Natural gas demand breaks down approximately into thirds: 1/3 power generation, 1/3 retail/commercial, and 1/3 industrial demand. Should the economy remain depressed, natural gas demand will likely continue to suffer.
-Absent a record cold winter and a substantial increase in natural gas demand (with coal-natural gas parity at roughly $4.50, natural gas-to-coal switching should increase given that the Henry Hub spot > $4.50), the U.S. will probably exit the winter with record amounts of natural gas storage/inventory, which will likely cause price of natural gas to remain depressed relative to the long-dated $7.00+/mcf NYMEX natural gas contracts.
Execution Risk—Preceding its early success in the Haynesville, EXCO had been considered a mediocre operator given some drilling missteps in certain plays in the past. While it has proven to be a capable operator in the Haynesville where its portfolio includes some of the most successful wells in the play, it is difficult to conclude that it will be able to achieve similar successes in future Haynesville, Marcellus, Bossier, Huron, or other wells. The challenge with execution risk is that it is difficult to mitigate with hedges, whereas various macro and industry factors can be hedged.
Regulatory Risk—While most of the current pending national legislation, including the “Natural Gas Act” (HR 1835 and S1408) as well as any potential carbon legislation, whether “Cap and Trade” or other, might ultimately benefit natural gas producers given the comparative advantages of natural gas compared to other transportation and power generation fuels, any regulation that negatively impacts natural gas consumers and producers would likely include EXCO. The biggest concern would probably be regulation affecting the cost of exploiting natural gas—whether higher royalties/severance/ad valorem taxes or more stringent guidelines regarding the emissions or water impact that drilling might have in particular regions.
Business Description and Net Asset Value (“NAV”) Breakdown
EXCO Resources, Inc. (XCO) is an independent oil and natural gas company that acquires, develops, and exploits oil (6% of ’08 Proved reserves, 9% of ’09 production, and 22% of ’09 unhedged revenue) and natural gas (94% of ’08 Proved reserves, 91% of ’09 production, and 78% of ’09 unhedged revenue) properties in the United States. At year-end 2008, EXCO’s portfolio was made up of producing properties in East Texas/North Louisiana, Appalachia, the Mid-Continent, Permian, and the Rockies, but following a series of non-core asset divestitures during the course of 2009 the company sold its Mid-Continent, Rockies, and its Appalachian properties in Ohio and Northwest Pennsylvania. The portfolio is now concentrated in the East Texas/North Louisiana region where EXCO is targeting resources found in the Haynesville and Bossier shale formations as well as the Cotton Valley Lime, in Appalachia where the company is targeting mostly natural gas in the Marcellus shale, and lastly in the Permian Basin where it is targeting non-shale formations. During 2008, EXCO produced 144.6 Bcf (395 mmcfe/d) of natural gas-equivalent resources, including 131.2 Bcf (358.4 mmcfe/d) of natural gas and 2.2 mmbbls (6,109 bbls/d) of oil, and following its divestitures in 2009 it is currently producing 235 mmcfe/d of natural gas-equivalent resources that continue to be 91% natural gas and 9% oil. EXCO boasts 910,000 net acres and 1,107,000 gross acres under lease on a pro forma basis, with approximately 50% of those acres considered developed and the other half undeveloped.
East Texas/North Louisiana Division (177 mmcfe/d of current production; 168,000/250,000 net/gross acres; 0.817 Tcfe of pro forma proved reserves, a 12.6-yr. reserve life, as of 9/23/09 w/ 2.4 Tcfe of proved, probable, and possible reserves (“3P”), and 3.8 Tcfe of 3P+ reserves):
1) Haynesville Shale—The Haynesville Shale in East Texas/North Louisiana is the lynchpin of EXCO’s resource portfolio. Unlike various competitors that entered the play in 2008-2009 by paying $30,000+ per acre for prospective acreage, EXCO acquired its acreage starting in 1998 when it was focused on long-lived conventional natural gas potential and then it serendipitously ended up in the premier Haynesville acreage in DeSoto Parish and Caddo Parish, Louisiana (its Holly-Caspiana Field) when the play was discovered two years ago. Results so far reflect the quality of its acreage as XCO boasts the two best Haynesville wells to date in terms of productivity and 15 of the top 39 (of 165 total) wells that have been reported thus far (Exhibits 1 & 2 on pages 8 & 9).
Haynesville Joint Venture with BG Group (BG LN, formerly British Gas)—EXCO found itself with 84,000 premier acres prospective for the Haynesville Shale in early 2009; however, it had $3.0B worth of total debt at year-end 2008, and without the fresh capital needed to both deleverage and develop its acreage in an otherwise weak natural gas price environment EXCO would have been forced to wait for stronger commodity prices to lift free cash flow in order to fill the void. As favorable drilling results started to emerge from the play with EXCO at the center of the progress, on June 30th it was announced that BG Group plc of London and EXCO entered into a 50%-50% Joint Venture where upon closing (August 2009), BG would pay XCO $1.3B for 50% of its Haynesville potential and the midstream assets that serve the prospective region. As a part of the deal, BG paid XCO $655mm for 207 Bcfe of non-shale proved reserves in the region plus a 50% interest in EXCO’s Haynesville and related upstream assets, and BG agreed to fund 75% of XCO’s drilling and completion costs in the Haynesville and Bossier shales up to $400mm (meaning that BG will ultimately fund 87.5% of the ~$1.1B expected capital investment in the Haynesville required over the next several years).
The two key benefits of the deal were: 1) XCO’s Haynesville resource potential should be realized with a materially lower capital investment required from XCO shareholders while at the same time free cash flow and production growth should ramp disproportionately; 2) The $1.3B and another $1B of divestiture proceeds year-to- date have allowed the company to reduce its debt from $3.0B+ to $999.4mm of total debt on a pro forma basis, or $888.7mm of net debt as of the end of October. At the time, it was said that the area of mutual interest (“AMI,” the acreage contained in the JV) contained 1,600 undrilled Haynesville locations and 4-6 Tcfe of natural gas upside, meaning that the 84,000 net acres will be divided evenly between the partners (50/50 working interest split) and the natural gas upside will be evenly split as well with 2-3 Tcfe of potential to each of XCO and BG.
Haynesville NAV: The estimated current Net Asset Value of EXCO’s Haynesville opportunity is $2.584B ($1.01/mcfe x 2.557 Tcfe), or $11.92/share, based on a 30.0% average working interest and 20.0% royalty leading to a ~24.0% net revenue interest in 1,061 risked potential locations assuming an 8.0 Bcfe estimated ultimate recovery (“EUR”) per well and a $9mm 2009 completed well cost declining over time to a long-term $7.5mm completed well cost by 2012. This thesis assumes that 25% of its acreage will not work, and that 5% of its wells will not succeed, yielding a total risk factor of 29% (success factor of 71%)—meaning that only 71% of the total potential will be realized, leaving room for some upside to this estimate. The 8 Bcfe EUR assumption is the result of using a conservative 12.7 mmcfe/d initial production (“IP”) estimate (though most of XCO’s wells have seen IPs of 20+ mmcfe/d) and a hyperbolic production decline assumption where an 80% first year decline rate gives way to a second year decline of 33%, etc. Commodity prices assumed are the NYMEX oil and natural gas futures strips and an 8% discount rate (which are homogenous assumptions used throughout this analysis and comparative industry comments).
2) Bossier Shale—A new frontier for the industry and for EXCO, the company believes that it has ~17 Tcfe of potential gas-in-place under its East Texas/North Louisiana acreage associated with the Bossier Shale play. XCO commenced the drilling of its first horizontal well targeting the Bossier Shale during 4Q’09 and results should be forthcoming during 1H’10, with vertical well tests being drilled in six other counties at the same time. Importantly, this thesis assigns very little value to EXCO’s Bossier opportunity—starting with the assumption that it will ultimately recover 1 Tcfe of risked resource potential (relative to its 17 Tcfe estimate of gas-in-place) and assigning $0.20/mcfe of value to the play, the result is Net Asset Value of $200mm, or $0.92/share. This is a key source of potential upside going forward as the play has been conservatively valued until more is known about its viability and economics.
3) Cotton Valley and the Vernon Field—XCO currently records 275 Bcfe of proved reserves in its Cotton Valley development and 422 Bcfe of proved reserves in its Vernon Field, and it estimates that it has an incremental 268 Bcfe of 3P+ potential reserves in the Cotton Valley formation and 525 Bcfe of 3P+ potential reserves in the Vernon Field. This thesis has assigned no value to the potential Cotton Valley and Vernon upside, although if EXCO’s estimates are correct the 793 Bcfe of resource potential in the two targets could add $1.83/share of Net Asset Value to XCO assuming a conservative $0.50/mcf value for the gas.
Appalachia Division (37 mmcfe/d of current production; 640,000/714,000 net/gross acres; 0.333 Tcfe of pro forma proved reserves, a 24.7-yr. reserve life, w/ 0.5 Tcfe of 3P reserves and 7.5-13.1 Tcfe of 3P+ reserves):
1) Marcellus Shale—Likely the source of the most incremental upside in the portfolio, XCO boasts 348,000 net acres in Pennsylvania and West Virginia that are prospective for the Marcellus Shale with what it estimates to be 226,000 net acres in the “fairway” of the play, 70% of which are held by prior production so that it will not be forced to drill before it is ready and thus optimize the economics of the play by taking its time to develop the acreage as its expertise of the geology and opportunity progresses and as the play is “de-risked” by peers also drilling in the surrounding areas. EXCO believes that it has 6-11 Tcfe of potential reserves in its acreage, and it expects to resume horizontal drilling in 2010 applying its successful practices from the Haynesville to its strategy in the Marcellus. While there is great potential, there remains substantial risk and as a result this thesis assigns a risk factor of 73% (70% acreage risk and a 90% well success rate) to EXCO’s Marcellus potential—meaning that it only gives the company credit for 27% of the opportunity, or 2.25 Tcfe of risked resource potential compared to the 6-12 Tcfe quoted by the company leaving room for upside to this analysis.
Marcellus NAV: The estimated Net Asset Value of EXCO’s Marcellus opportunity is $1.431B ($0.64/mcfe x 2.25 Tcfe), or $6.60/share, based on a 96.0% average working interest and 12.5% royalty leading to an 84% net revenue interest in 939 risked locations assuming a 2.5 Bcfe EUR per well and a $4mm well cost. It is important to point out that this analysis incorporates a $0.00/mcf basis premium (the current premium is around $0.30/mcf) applied to the NYMEX oil and gas strips despite the fact that the Marcellus Shale is located right next to the key New York end market which means that transportation costs are minimal and therefore the gas should sell at a premium to the Henry Hub, Louisiana NYMEX benchmark natural gas.
2) Huron Shale—XCO has 129,000 net acres in the Huron Shale play in West Virginia where it believes that it has ~1 Tcfe of potential reserves. EXCO’s Huron opportunity is relatively small and a higher risk play, and as such it is not yet devoting much capital to the play given its opportunities elsewhere. The result is that very little value is assigned to the Huron Shale in this analysis--$171.3mm of Net Asset Value, or $0.79/share, assuming an 18% success factor (82% total risk = 80% acreage risk and a 90% well success rate) and assuming 120-acre spacing, 167 risked locations, an average of 85.6% working interest, a $1.2mm completed well cost, and a 1.3 Bcfe EUR assumption per well.
Permian Division (20 mmcfe/d of current production; 102,000/143,000 net/gross acres; 0.077 Tcfe of pro forma proved reserves, a 10.5-yr. reserve life, w/ 0.1 Tcfe of 3P reserves and 0.3 Tcfe of 3P+ reserves)—Located in West Texas/Southeastern New Mexico, the Permian has traditionally been a mature field where producers use waterflooding and other enhanced recovery techniques to extract oil; however, EXCO focuses on conventional natural gas recovery and believes that it has 1,000+ potential remaining locations to exploit.
Midstream and Marketing Division—EXCO’s Marketing and Midstream Division consists of its 50% interest in the newly-formed TGGT Holdings, LLC (“TGGT”) to which it contributed its East Texas/North Louisiana midstream assets as a part of the JV with BG Group (BG bought the other half for $269mm along with its share of the Haynesville JV), and EXCO’s Vernon Field midstream assets that were not included in the deal with BG Group. Its total current midstream throughput (capacity) is 758 mmcf/d (508 mmcf/d TGGT throughput plus 250 mmcf/d of Vernon Field capacity), of which its equity revenue throughput is 381 mmcf/d. TGGT’s assets consist of the Talco gathering system (318 mmcf/d) which includes 11 gathering systems and six gas conditioning skids along with 625 miles of gathering lines supported by long-term contracts, the TGG Transportation System (revenue throughput of 190 mmcf/d and capacity of 390 mmcf/d without compression, 530 mmcf/d with compression) which offers access to four cryogenic plants and 12 interstate pipelines, and the Haynesville Header System which is a 36” intrastate pipeline on which construction began in July 2009 with the expectation that the 29-mile line will be fully operation by 1Q’10.
1) Marcellus JV w/ BG Group or other large E&P or integrated hungry for prime U.S. unconventional exposure.
2) Substantial upside to production growth guidance, and large increases in proved reserves over the next three years.
3) BG acquisition of XCO.