Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

- Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

Thursday, August 11, 2011
PwC

Ongoing interest in shale acreage, deals for midstream assets and increased investments from foreign buyers in the U.S. oil and gas industry helped drive U.S. oil and gas mergers and acquisitions (M&A) value to $39 billion in the second quarter of 2011, according to PwC US.

In the second quarter of 2011, there were 51 deals with values greater than $50 million, compared to 61 announced deals totaling $41 billion in the same period last year. While the volume and value of transactions dipped slightly in the second quarter of 2011 when compared to the same period last year, average deal value for deals over $50 million jumped to $765 million in the second quarter 2011, a 14 percent increase over the same period last year when average deal value was $672 million.

"There continues to be steady M&A activity in the oil and gas sector with strong competition for prized assets, which has maintained the deal momentum throughout the first half of the year. The second half of the year has already kicked off with one mega deal announced, and we expect that deal momentum to continue," said Rick Roberge, principal in PwC's energy M&A practice. "Foreign and private equity interest in North American oil and gas assets remains very high and will likely be a driver of ongoing activity."

Foreign buyers announced 18 deals valued at over $50 million or more in the second quarter of 2011, which contributed $36.2 billion or 72 percent of total deal value, versus 27 deals valued at $24.2 billion in the same period last year.

For deals valued at over $50 million, there were 11 midstream deals that accounted for $19.9 billion, or 51 percent of total deal value, compared to six deals worth $3.4 billion in the same period last year. Transactions in the upstream space led all oil and gas subsectors with 26 deals, or 51 percent of volume in the second quarter.

According to PwC, seven of the top 10 deals by value in the second quarter of 2011 were related to shale plays, including four upstream deals and three transactions in the midstream and oil field services space. For all deals greater than $50 million, there were 10 shale-related transactions totaling $7.5 billion, or 19 percent of total deal value, including two deals involving the Marcellus Shale totaling $2.3 billion.

"Shale-gas assets continue to be very attractive acquisition targets as multinationals look to gain technical know-how and exploit the long-term value and opportunities from rising energy needs," said Steve Haffner, a Pittsburgh-based partner with PwC's energy practice. "At the same time, there is tremendous activity developing around natural gas infrastructure, which is necessary to move the extracted gas to market. The U.S. 'shale gale' continues to attract the attention of global companies."

There were five financial sponsor-backed transactions over $50 million, representing $6.1 billion, or 16 percent of total deal value, compared to 10 financial sponsor deals contributing $6.2 billion during the same period last year. During the first six months of 2011, there were 16 financial sponsor deals contributing $20.6 billion, a whopping 129 percent increase in deal value, compared to the first half of 2010 when there were 15 financial sponsor-backed deals, valued at $9.0 billion.

"With oil prices hovering at $100, private equity funds continue to make a very strong push in the oil and gas sector," added Roberge. "The private equity deal makers, who used to largely play in the midstream space, are now heavily involved in exploration and production (E&P), shale plays, and oil field services and equipment sector. However, along with the great opportunities and rewards of investing in oil and gas, there is still risk in this space – and new entrants need to understand the pitfalls before trying to exploit these possible opportunities."

For deals with values greater than $50 million, there were 18 corporate transactions totaling $26.8 billion or 69 percent of total second quarter deal value, compared to 22 deals that accounted for $25.9 billion in deal value in the same period last year. Thirty-three asset deals for a combined total of $12.2 billion were announced in the second quarter of 2011, versus 39 deals totaling $15.1 billion in the same period last year. However, when comparing the first six months of 2011 to the first half of 2010, the number of corporate transactions increased by three deals to 35 transactions, while total corporate deal value jumped 26 percent to $59.7 billion in 2011 from $47.6 billion in 2010.

Another potential driver for M&A activity is the desire from some oil companies to sell assets and break apart key lines of business, according to PwC.

"We believe that another factor to keep a close eye on throughout the year, which may add to the already robust M&A activity we're seeing, is the trend of integrated oil companies looking at the various options to unlock shareholder value through separating their E&P businesses," said Roberge. "While this trend could be a very positive driver of M&A activity, these are highly complex transactions with potential consequences around tax considerations, valuations and financial reporting. Companies should consider the risk with these types of transactions as every potential scenario needs to be thoroughly and diligently evaluated to succeed."

PwC's Oil & Gas M&A analysis is a quarterly report of announced U.S. transactions with value greater than $50 million analyzed by PwC using transaction data from John S. Herold, Inc.

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Record Output, Higher Prices Drive Devon's 2Q Profit to $2.7B

- Record Output, Higher Prices Drive Devon's 2Q Profit to $2.7B

Wednesday, August 03, 2011
Devon Energy Corp.

Devon reported net earnings of $2.7 billion for the quarter ended June 30, 2011, or $6.50 per common share ($6.48 per diluted share). This is a 288 percent increase compared with second-quarter 2010 net earnings of $706 million, or $1.59 per common share ($1.58 per diluted share).

For the six months ended June 30, 2011, Devon reported net earnings of $3.2 billion, or $7.44 per common share ($7.41 per diluted share). This compares with net earnings for the six months ended June 30, 2010, of $1.9 billion, or $4.26 per common share ($4.24 per diluted share).

Second-quarter 2011 financial results were impacted by certain items securities analysts typically exclude from their published estimates. The most significant of the adjusting items was a $2.5 billion gain on the sale of assets in Brazil. Excluding adjusting items, Devon earned $726 million or $1.71 per diluted common share in the second quarter. The adjusting items are discussed in more detail later in this news release.

Record Production and Higher Prices Drive Oil and Gas Sales

Sales of oil, natural gas, and natural gas liquids from continuing operations were $2.2 billion in the second quarter of 2011, a 23 percent increase over the second quarter of 2010. Both higher production and higher oil and natural gas liquids pricing contributed to the increase.

Devon's North American onshore production averaged the highest daily rate in the company's history at 660,000 oil-equivalent barrels (Boe) per day in the second quarter of 2011. This represents a production increase of more than six percent over the second-quarter 2010, driven by a 12 percent increase in oil and natural gas liquids production.

Devon's marketing and midstream operating profit totaled $148 million in the second-quarter 2011, a 19 percent increase over the second quarter of 2010. The improvement resulted from higher natural gas liquids production and prices as well as increased gas throughput.

Strategic Repositioning Completed; Share Repurchase Plan Remains on Schedule

In May, the company closed the $3.2 billion sale of its Brazilian operations. Devon has now substantially completed its International and Gulf of Mexico divestiture plan. In aggregate, sales proceeds from the combined divestitures exceeded $10 billion with after-tax proceeds expected to approximate $8 billion.

"The execution of Devon's strategic repositioning was excellent," said John Richels, president and chief executive officer. "Devon has emerged with a pristine balance sheet, a deep inventory of oil and liquids-rich growth opportunities and a highly competitive cost structure. As demonstrated by our second-quarter results, the repositioned Devon is delivering profitable growth per share."

In May 2010, Devon commenced a program to repurchase $3.5 billion of its common stock. As of June 30, 2011, the company had repurchased 33.5 million shares at a total cost of $2.5 billion. Devon expects to complete the stock repurchase program by the end of 2011.

Production Growth Leads Operating Highlights

• In the Permian Basin, Devon increased production 17 percent over the second quarter of 2010, to 49,000 oil-equivalent barrels per day. Oil and natural gas liquids accounted for 75 percent of the quarter's production.
• The company completed nine operated Bone Spring wells within the Permian Basin in the second quarter. Initial daily production from the nine wells averaged more than 700 Boe per day per well. Devon has an average working interest of 77 percent in these wells.
• In Canada, Devon commenced steam injection and achieved first production from its Jackfish 2 oil sands project in the second quarter. Production from the 100 percent-owned project is expected to ramp-up to 35,000 barrels per day before royalties over the next 18 months.
• Production from the company's Cana-Woodford Shale play averaged a record 189 million cubic feet of natural gas equivalent per day in the second quarter, including nearly 9,000 barrels per day of liquids. This represents an 80 percent increase in total production compared to the year-ago quarter.
• Devon's Barnett Shale production increased 13 percent over the second-quarter 2010 to a record 1.3 billion cubic feet of natural gas equivalent per day, including 46,000 barrels per day of liquids production.
• Devon brought eight operated Granite Wash wells online in the second quarter. Initial production from these wells averaged 2,010 barrels of oil-equivalent per day, including 200 barrels of oil and 730 barrels of natural gas liquids per day. The company has an average working interest of 71 percent in these wells.
• The company has assembled 1.1 million net acres targeting new oil and liquids-rich gas opportunities across multiple basins in the U.S. Devon plans to drill more than 30 wells this year targeting the Tuscaloosa Marine Shale, Niobrara Shale, Mississippian Lime, Ohio Utica Shale and the A1 Carbonate and Utica Shale in Michigan.

Cost Containment Efforts Offset Rising Industry Costs

Lease operating expenses (LOE) were $453 million in the second quarter of 2011, or $7.55 per Boe. This represents a one cent per Boe decrease from the second-quarter 2010. Effective cost management and higher production offset the effects of the strengthening Canadian dollar and rising service and supply costs.

Taxes other than income increased $28 million to $120 million in the second quarter of 2011. The year-over-year increase was driven by higher production taxes, resulting from the significant increase in oil and natural gas liquids revenues.

Second-quarter 2011 general and administrative expenses (G&A) totaled $135 million, or $2.26 per Boe. Compared to the second quarter of 2010, G&A per Boe increased approximately two percent. Efficiencies gained through the company's strategic repositioning helped mitigate the effects of the strengthening Canadian dollar and an increase in overall activity levels.

Depreciation, depletion and amortization expense (DD&A) of oil and gas properties increased to $485 million in the second quarter of 2011. Compared to the year-ago quarter, unit DD&A increased 11 percent to $8.08 per Boe.

Interest expense decreased 24 percent in the second quarter to $85 million. Second-quarter 2010 interest expense included a $19 million charge related to the early redemption of senior notes.

Second-quarter income tax expense from continuing operations totaled $1.2 billion, or 87 percent of pre-tax earnings. This unusually high tax rate resulted from a $744 million charge related to U.S. income taxes on foreign earnings assumed to be repatriated under current U.S. tax law. After adjusting for this and other items generally excluded by securities analysts, Devon's second quarter tax rate totaled 32 percent of pre-tax earnings from continuing operations.

Cash Flow and Divestiture Proceeds Total $4.8 Billion

Cash flow before balance sheet changes totaled $1.6 billion in the second quarter of 2011, a 115 percent increase over the year-ago quarter. In addition, Devon received $3.2 billion of pre-tax proceeds from the sale of its assets in Brazil.

As of June 30, 2011, the company's cash and short-term investments reached $6.7 billion and its net debt to adjusted capitalization ratio declined to five percent. Reconciliations of cash flow before balance sheet changes, net debt and adjusted capitalization, which are non-GAAP measures, are provided in this release.

Devon Adds To Natural Gas Hedges

Devon continued to bolster its natural gas hedge positions for 2011 and 2012. For the second half of 2011, the company now has approximately 980 million cubic feet per day protected utilizing swap and collar contracts with a weighted average floor price of $5.28 per Mcf. For 2012, Devon now has hedges covering 815 million cubic feet per day hedged at a weighted average floor price of $4.89 per Mcf. The company's natural gas hedges for both 2011 and 2012 are based on the Henry Hub benchmark index.

Divestitures Impact Reported Financial and Operational Results

In accordance with accounting standards, Devon has classified the assets, liabilities, and results of its international segment as discontinued operations for all accounting periods presented in this release. Included with this release is a table of revenues, expenses, production categories, and the amounts classified as discontinued operations for each period presented.

Items Excluded from Published Earnings Estimates

Devon's reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company's financial results. These items and their effects upon reported earnings for the second-quarter 2011 were as follows:

Items affecting continuing operations

• U.S. income taxes on foreign earnings assumed to be repatriated to the U.S. decreased second-quarter earnings by $744 million.
• A change in the fair value of oil, gas and NGL derivative instruments increased second-quarter earnings by $357 million pre-tax ($233 million after tax).
• A change in fair value of interest-rate and other financial instruments decreased second-quarter earnings by $30 million pre-tax ($20 million after tax).
• Restructuring costs decreased second-quarter earnings by $6 million pre-tax ($3 million after tax).

Items affecting discontinued operations

• Divestitures of assets in Brazil resulted in a second-quarter gain of $2.5 billion pre-tax ($2.5 billion after tax).
• Restructuring costs increased second-quarter earnings by $8 million pre-tax ($5 million after tax).

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Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

- Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

Wednesday, June 15, 2011
Rigzone Staff
by Karen Boman

The U.S. shale oil and gas drilling boom boosted U.S. oil and gas reserve growth to a five-year high in 2010, while upstream spending more than doubled from 2009 to 2010 largely due to producers' acquisitions of shale properties, according to Ernst & Young's fourth annual U.S. E&P Benchmark Study.

The survey of the 50 largest oil and gas companies by end-of-year reserves found that end-of-year oil reserves grew 11 percent from 16.1 billion barrels in 2009 to 17.8 billion barrels in 2010, and natural gas reserve grew 12 percent from 156.2 Tcf in 2009 to 174.3 Tcf in 2010, the strongest combined annual growth posted from 2006 to 2010.

Shale Rock

The oil production replacement rate for U.S. oil reserves from all sources, including extensions and discoveries, improved recovery, revisions, purchases and sales of proved reserves, was 234 percent in 2010, compared with a 158 percent replacement rate in 2009. The U.S. natural gas production replacement rate from all sources was 252 percent last year, compared with 156 percent in 2009.

Production replacement rates for 2010 that excluded purchases and sales were 205 percent for oil, 249 percent for gas, and 232 percent on a combined BOE basis.

The study found that independent oil and gas producers led in terms of oil production replacement rates for 2010, with independents replacing 601 percent of oil production from all sources last year and, excluding purchases and sales, replacing 433 percent of oil production.

Large independents replaced 241 percent of production from all sources, and 290 percent of production from sources other than purchases and sales. Meanwhile, integrated oil and gas companies replaced 141 percent of oil production from all sources, and 111 percent of production from sources excluding purchases and sales.

Integrated companies had a gas production replacement rate of 436 percent from all sources; however, this replacement rate reflects ExxonMobil's acquisition of XTO Energy, which was completed in June 2010. When purchases and sales were excluded, integrated companies had a gas production replacement rate of 111 percent.

Independents replaced 408 percent of gas production from all sources in 2010, or 375 percent when purchases and sales were excluded. Large independents recorded a negative gas production replacement rate of 34 percent, largely due to the ExxonMobil/XTO transaction, as XTO is classified as a large independent. Excluding purchases and sales, large independents had a gas production replacement rate of 263 percent in 2010.

Reserve replacement costs on a total basis, including proved property acquisitions, were up once again, increasing to $15.26 per BOE in 2010 from $12.78 per BOE in 2009. Reserve replacement costs on a finding and development basis, excluding proved property acquisitions, increased to $17.84 per BOE, up from $13.01 per BOE in 2009.

Upstream spending more than doubled from $72.8 billion in 2009 to $177.9 billion in 2010. ExxonMobil's acquisition of XTO Energy accounted for 51 percent of proved property acquisition costs of $42.2 billion and 40 percent of unproved property acquisition costs of $59.3 billion in 2010. Apache Corp.'s acquisition of Mariner Energy and assets from Devon Energy and BP contributed significantly to proved and unproved property acquisition costs, as did acquisitions by Chesapeake Energy and Denbury Resources.

Exploration costs increased eight percent from $14.3 billion in 2009 to $15.5 billion in 2010, while development spending increased 36 percent from $44.8 billion in 2009 to $60.8 billion in 2010, primarily due to shale oil and gas development. The increase in exploration and development spending was primarily driven by ExxonMobil, Chesapeake Energy and EOG Resources. Of the 50 companies surveyed, only four decreased their exploration and development spending in 2010 – BP, ConocoPhillips, Loews and Plains Exploration & Production.

The companies' plowback percentage, or total upstream spending as a percentage of netback, increased to 170 percent in 2010, the highest of the five-year period from 2006 to 2010, as companies reinvest in shale activity. In 2006, the plowback percentage reached 121 percent as a result of an increase in investment activity driven by a relatively high priced commodity environment.

ExxonMobil's acquisition of XTO and similar deals are part of the trend of major oil and gas companies following the lead of independent oil and gas companies, who were first movers in North American shale plays. This trend is occurring as integrated majors are finding it difficult to replace reserves organically. The rise of national oil companies overseas has made it more difficult for the companies to access foreign reserves, as have restrictions placed U.S. offshore drilling. U.S. independents and oil service companies have been at leading edge of technology, including developments in horizontal drilling, which have changed the oil and gas industry.

Horizontal drilling

Strong oil prices and weak, but stable, gas prices in 2010 encouraged investment in shale exploration efforts and production technology. The shift from gas to oil-focused drilling has created a drilling renaissance in the Permian Basin that has operators looking at plays nobody thought was possible.

However, consistency in commodity prices, as well as companies' abilities to find enough skilled employees and addressing issues surrounding hydraulic fracturing, are needed to allow companies to capitalize on shale properties. Despite controversy over hydraulic fracturing, the practice will likely continue, said Marcela Donadio, Americas Oil & Gas Leader for Ernst & Young, noting that companies are taking efforts to conduce fracing responsibly.

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