Mystery Solved. Barnett Shale Valuation Benchmark

Legend snags Range's Barnett assets for $900 million

Also South Texas properties for $99 million

PLS estimates Legend paid Range $7,965 per daily Mcfe.

Legend Natural Gas IV agreed to acquire Range Resources' Barnett shale assets in a deal valued at $900 million, marking the company's entry into the Fort Worth Basin.

The properties include 390 producing wells and ~52,000 net acres.

Net production is 113 MMcfe/d (86% gas). Net reserves were not disclosed but an offering memorandum by Scotia Waterous indicates 1.7 Tcfe in 3P reserve potential.

Range is keeping some non-producing acreage in the Barnett, which it values at ~$50 million.

Range said the Barnett sale would be a catalyst for making the company cash flow positive in 2013. Under its plan, Range will retain 100% of the resource potential of its Marcellus shale play as well as its Upper Devonian and Utica Shale plays. The Barnett sale would let Range pursue other opportunities in West Virginia's Nora area, the Mid-Continent and Permian Basin.

Speaking on a conference call with analysts, Range CEO John Pinkerton said the $900 million sale price was $200 million below expectations. Pinkerton said, "If we felt the futures prices for natural gas were going to move materially higher in the near term, we would have waited for prices to rebound before selling the Barnett properties...We view the sale as recycling capital from lower-return properties into higher-return properties."

Pinkerton went on to say that Range's decision to sell was strengthened by the exemplary results the company was having in the Marcellus, Nora, Mid-Continent and Permian. "Given our results in these areas and our extensive inventory of opportunities, we believe recycling the Barnett sales proceeds into these higher-return projects was the right thing to do for Range and its shareholders. While we prefer to sell properties in a higher price environment, our thought was that we would reinvest the proceeds back into higher-return projects in essentially the same relative natural gas price environment," the CEO said.

"Given the expense of Barnett drilling and the good margins offered in the Marcellus, Range has opted to monetize the Barnett assets and use the proceeds to develop the Marcellus. The $900 million of Barnett proceeds, coupled with cash flow and another $200 to $250 million in expected non-core asset sales this year, "not only funds 2011 Marcellus development but also carries $400 million forward for 2012 development," analysts at Seeking Alpha reported.

Legend's second deal, a $99.2 million acquisition from Smith Production, complements Legend's long-standing South Texas position. The acquisition includes the Samano and Santa Fe Vicksburg fields in Starr and Hidalgo Co, 20 miles from Legend's West La Grulla Field. The properties include 83 operated wells producing 8.8 MMcfe/d net (65% gas) and ~7,200 net acres. Legend's equity is provided by the Riverstone/Carlyle Global Energy and Power Funds.

Encana plans to divest Barnett assets

Analysts say the deal could bring $800 million to $1 billion

As part of an ongoing divestiture program, Encana Oil & Gas set the wheels in motion to divest its Barnett Shale assets. The overall divestiture program is expected to bring between $1.0 and $2.0 billion, and the Barnett could bring between $800 million and $1.0 billion.

Encana's Barnett assets hold strong potential for future development. The assets produce ~125 MMcfe/d and include the associated processing and pipeline facilities on ~52,000 net acres. Encana enjoyed an early mover position in the play with the 2004 purchase of Tom Brown Inc. for $2.7 billion. The deal was intended to establish a strong position in the Rocky Mountains. The words "Barnett Shale" were not found in the original press release. So much can change in seven years. The Barnett provided Encana with high-quality natural gas growth and foundational knowledge which the company has applied across its U.S. and Canadian portfolio of newer resource plays. That knowledge will continue to provide Encana with operational expertise as the company applies multiple advanced technologies to manage costs over the long term and pursue maximizing the margins from all of its natural gas production. Encana's development of the Barnett has been a springboard of knowledge that the company has used to develop other shale plays. Encana holds 250,000 net acres in the Tuscaloosa Marine Shale and 365,000 net acres in Canada's Duvernay Shale.

Jim Jarrell, a managing director at ITG Investment Research in Calgary, told The Globe & Mail that potential buyers would have to be optimistic about gas prices and their operating acumen to make these assets attractive. Encana has slowed drilling activity in the zone, and production has been falling since 2008. Natural gas would have to trade at ~$5/MMBtu on the NYMEX in order to break even so buyers would have to believe that they can lower costs or that gas prices will rally to make it work, Jarrell said. To some it might be curious Encana is selling its Barnett assets, but as Mike Dunn of FirstEnergy told The Calgary Herald, it accounts for ~4% of production (net of royalties) and thus wasn't exactly a driver behind the stock price. In April, Range Resources sold its Barnett assets to Legend Natural Gas for ~$900 million. The assets are similar to Encana's in scope -volumes of 113 MMcfe/d and an acreage position of 52,000 net acres. In June, Encana and PetroChina abandoned plans for a $5.5 billion JV to develop a large tract of shale gas in western Canada after failing to agree on terms. Had that deal gone forward, Encana may not have decided to sell its Barnett assets in this time of low prices.

"Encana is under pressure to sell assets or face a decline in capital spending, said Mark Gilman, an analyst with Benchmark Co. in New York. "They do not have a whole lot of balance sheet capability or cash on hand," Gilman told Bloomberg News. To learn more, request PLS Listing No. PP 1693DV or contact Scotia Waterous.

Clayton Williams cuts capex as Wolfbone well count drops

Clayton Williams Energy revised capex to $385 million in fiscal 2011 on E&D activities, a reduction of $54 million from earlier estimates. Substantially all of these cost reductions relate to the company's planned activities in its Reeves Co. Wolfbone play. Changes include a reduction in the total number of wells that CWEI expects to be able to drill in the area during the remainder of the year and an increase in the estimated number of those wells in which the company will own 75% WI versus 100% WI. These reductions were partially offset by an increase in the estimated cost to drill and complete each of its Wolfbone wells from $3.8 million to $4.2 million as a esult of changes n the planned frac design.

The company has also revised downward its expected production for the remainder of 2011 in connection with the shift in capital spending to the Reeves Co. Wolfbone play. Since its last guidance in May, the company has reduced the planned rig count in Andrews Co. from three rigs to one and has dropped both rigs previously allocated to the Austin halk in order to allocate resources to ts Wolfbone play. In addition, estimated production from the Andrews Wolfberry play was revised downward due to continuing frac delays and revisions in production based on well performance.

GMX: Three Forks horizontal ready for completion

GMX Resources completed the drilling of its first Three Fork horizontal well. The Wock 21-1-1H in Stark Co., North Dakota reached TD of 21,151 ft. with a horizontal lateral length of 10,281 ft., which included drilling a vertical pilot hole and performing additional testing. Oil shows were predominant in the vertical and horizontal lateral while drilling in the Three Forks formation.

The Wock 21-1-1H well is scheduled for a 41-stage completion with oil production expected by October 1. The company expects to spud its second Three Forks horizontal well, the Frank 34-4-1H, also in Stark Co., shortly. Permits are pending for the next two Bakken/Three Fork wells: the Evoniuk 21-2-1H in Billings Co., a Three Forks horizontal that is expected to spud in October, and the Akovenko 24-34-1H, in McKenzie Co., the company's first horizontal Bakken well that is scheduled to spud in November. The company has 12 additional permits in process for wells located in Billings, McKenzie and Stark Co. in North Dakota.

Murphy takes another step in exiting the refining business

Sells Meraux refinery to Valero for ~$625 million

Just over a year ago, Murphy Oil said it would exit the refining business to focus on its E&P segment. The company sold its last U.S. refinery to Valero Energy for $325 million, plus $300 million for the value of inventory. Meraux represents the second, and final refining asset sale in the U.S.

The Meraux, Louisiana, refinery has a capacity of 135,000 b/d. It has a Mississippi River dock, pipelines to Collins, Mississippi, and is located ~40 miles from Valero's refinery at Norco, Louisiana. The deal also includes a product terminal, 20% of the Collins Product Pipeline and terminal and 3.2% of the Louisiana Offshore Oil Port. The Meraux refinery also includes a 34,000 b/d hydrocracker and significant hydroprocessing capacity for clean diesel production. "The $325 million price tag allows Valero to boost its capacity in a way that's less expensive than upgrading existing equipment at its other refineries," Morningstar analyst Allen Good was quoted by Dow Jones. "They can get a yield upgrade from using existing equipment and can avoid the capital costs," the analyst said.

Last month, Murphy agreed to sell its Superior, Wisconsin, refinery to Calumet Specialty Products Partners for $214 million, plus the value of inventory (~$260 million at the time), for a total transaction of ~$474 million. The refinery has a capacity of between 34,000 and 45,000 b/d. Still up for sale is Murphy's Milford Haven, Wales, refinery, along with the retail system in the United Kingdom. At the time of Murphy's decision to exit the refining market, the three plants had a combined refining capacity of 280,000 b/d but only generated 0.5% of the company's income. Marathon Oil completed the spin- off of its downstream business into Marathon Petroleum in June and ConocoPhillips plans a similar move early next year. BP's CEO said a refining spin-off is a possibility, but ExxonMobil and Chevron are so far planning to stick with the integrated business model. Chevron said it believes the refining segment is central to its value proposition and executing its long-term growth strategy, according to a Reuters report. ExxonMobil reported a 20% return on its chemicals and refining business in the last quarter.

See PLS' MidstreamNews for additional reporting and analysis.

E&P companies subpoenaed for shale gas data

Sources claim New York's state attorney general sent subpoenas to Range Resources, Goodrich Petroleum and Cabot Oil & Gas and that Chesapeake Energy was asked to answer similar questions. EXCO Resources and Quicksilver Resources confirmed receipt of subpoenas from the SEC. Goodrich confirmed receipt of subpoenas for information on gas wells and reserves in the Haynesville from both the New York AG and the SEC.

Cabot, Range and Chesapeake did not comment publicly. A June 26 article The New York Times was the most visible, but not the first to question the economics of shale gas. For more on the subject, see Prospects & Properties MarketAlert, December 29, 2009. Perhaps the simplest and most convincing argument for shale gas is made by the graph below. While the U.S. gas rig count has fallen from almost 1,600 rigs in 3Q08 to fewer than 900 today, production is up 26% and continues to grow. Few would argue that leasing costs can rise steeply with the success of a shale play and that drilling and completion costs are rising (see story on oil service company earnings on page 10) because of increasing complexity of the wells and the pricing power of a tight market. However, practice makes perfect; the knowledge gained and application of new technologies continues to produce impressive results. The naysayers' worst case scenarios for well decline rates and recoverable reserves seem at odds with the output seen from the fields.