Shale Sale

Even a cursory glance at the major deals in the oil and gas industry reveals a powerful trend that should continue into 2012: Robust M&A activity involving shale oil and gas plays. This table details all the acquisitions, divestitures and spin-offs in the oil and gas business (excluding pipelines) announced over the past 12 months. Note that this list is limited to deals of at least $800 million.

Source: Bloomberg

BHP Billiton’s (ASX: BHP, NYSE: BHP) acquisition of Petrohawk Energy Corp, a leading producer in the Eagle Ford Shale and the Haynesville Shale, topped the charts as the largest deal in the E&P patch. But BHP Billiton’s ambitions didn’t end with Petrohawk Energy; the Australia-based giant also acquired oil- and gas-producing properties in Arkansas’ Fayetteville Shale from Chesapeake Energy Corp (NYSE: CHK) in a deal worth USD4.75 billion.

Other international oil companies also got in on the act. Norway’s state oil company Statoil (Oslo: STL, NYSE: STO) agreed to acquire Brigham Exploration in a USD4.54 billion deal announced in mid-October. Although Brigham Exploration wasn’t in the model Portfolios, we highlighted the stock on several occasions as a solid bet on rising oil production in the Bakken Shale.

Marathon Oil Corp (NYSE: MRO) also acquired properties in the Eagle Ford Shale, while Noble Energy (NYSE: NBL) added acreage in Appalachia’s Marcellus Shale from coal producer Consol Energy (NYSE: CNX).

Over the past few years, major integrated oil companies such as BP (LSE: BP, NYSE: BP), Chevron Corp (NYSE: CVX), ExxonMobil Corp (NYSE: XOM) and Total (Paris: FP, NYSE: TOT) have invested billions of dollars to add exposure to shale oil and gas.

Four factors will continue to drive M&A activity in the shale oil and gas space.

1. The Prolonged Slump in US Natural Gas Prices

As we projected in Step Off the Gas, North American natural gas prices slumped to less than $3 per million British thermal units in early 2012–the lowest level since 2001-02. US natural gas prices have hovered near depressed levels for several years, largely because of rising production from the nation’s prolific shale plays. This oversupply of natural gas was exacerbated by a warmer-than-normal winter, which reduced gas withdrawals.

Although North American natural gas could rally if weather conditions or supply disruptions eat into inventories, prices should remain depressed for at least the next two to three years. In response to these near-term challenges, many North American E&P firms have shifted their emphasis to plays rich in oil and higher-value natural gas liquids (NGL).

However, we remain bullish on natural gas over the long term: The relatively clean-burning fossil fuel should win market share from coal in the utility sector, while the prospect of exporting liquefied natural gas could also help balance the market. To raise cash to finance ambitious drilling programs in oil- and NGL-laden plays, many producers are divesting noncore acreage, inking joint-venture deals with international oil companies or spinning off assets in master limited partnerships (MLP) and oil and gas trusts.

Leading shale player Chesapeake Energy has been at the forefront of this trend. The firm, which took on substantial amounts of debt to purchase huge swathes of acreage in prospective shale oil and gas plays, has inked a number of joint ventures with international oil companies in some fields and sold less-lucrative assets such as its position in the Fayetteville Shale. The company also spun off its pipeline and processing assets as Chesapeake Midstream Partners LP (NYSE: CHKM) and royalty interests in its Granite Wash acreage as Growth Portfolio holding Chesapeake Granite Wash Trust (NYSE: CHKR).

A prolonged period of low gas prices should prompt many producers to sell gas-bearing acreage to well-capitalized energy giants that have the financial wherewithal to take a long view on the commodity.  

2. Expiring Hedges

North American producers with substantial exposure to natural gas have maintained their profitability because of hedge books established when the commodity fetched higher prices. These protections have enabled firms to earn a higher rate of return than prices in the spot market would suggest.

But studies of producers’ aggregate hedge books suggest that the majority of these contracts will expire by the end of 2013, a looming development that should spur a number of asset sales, joint ventures and spin-offs.

3. Rising Services Costs Disadvantage Smaller Producers

The difficulty and expense of securing the necessary equipment, services and labor remain a challenge in many of the nation’s leading shale plays.  

Two key technologies are required to extract the resources trapped in shale and other “tight” reservoir rocks: horizontal drilling and hydraulic fracturing. Fracturing involves pumping a liquid into an oil or gas field to crack the reservoir rock and form channels through which the hydrocarbons can flow into a well. Generating the pressure necessary to create these fractures requires a large fleet of pump trucks and compressors.

Unfortunately, the number of fracturing crews available falls short of demand even though many teams work almost constantly. These delays have produced a significant backlog of incomplete wells awaiting fracturing. With these capacity constraints, smaller operators face difficulty (and higher costs) expanding their drilling programs or exploring new plays.

In late 2010, for example, Growth Portfolio holding EOG Resources (NYSE: EOG) reported output that fell short of analysts’ expectations, prompting its stock price to pull back. EOG’s disappointing quarter didn’t reflect poor execution or a subpar resource base–in fact, the company’s wells actually produced at better-than-anticipated rates. However, insufficient fracturing capacity, particularly in the Eagle Ford Shale, weighed on production growth.

To alleviate these constraints, some producers ink term contracts for a dedicated crew or crew. As larger producers have deeper pockets and acreage positions that require multiple fracturing crews, these firms have a leg up on the smaller fry in securing these in-demand services in multiyear deals.

Some smaller E&P names may be worth significantly more as part of a larger company that has the services capacity to better exploit the underlying acreage and grow production.

4. Low-Risk and Low-Cost Production

As operators hone their drilling and fracturing techniques, production costs in shale oil and gas plays have trended lower. Much of this effort focuses on identifying the best fracturing fluids as well as ideal well lengths and spacing.

That the US has managed to grow its overall oil and gas output at a time when production offshore Alaska and the Gulf of Mexico has declined is a testament to the quality of the onshore shale plays. In 2009 and 2010, the US managed to grow its total oil production for the first time in decades, while the nation surpassed Russia as the world’s leading gas producer in 2010.

The appeal of US shale plays to international oil companies is simple: These assets offer low-risk production growth in a politically stable nation–an increasingly rare combination. Acquirers also hope that the experience gained in US shale fields will enable them to exploit similar resources in other regions.

The Targets

Investors should focus on names with exposure to one or more of four unconventional fields: the Marcellus Shale, the Bakken Shale, the Eagle Ford Shale and the Permian Basin.

Of these plays, the Marcellus Shale is the lone natural gas play, but portions of the field contain meaningful quantities of ethane, an in-demand NGL that boosts wellhead economics. Moreover, the prolific nature of the Marcellus Shale and certain geological characteristics make the field one of the lowest-cost major plays in the US. The Marcellus Shale also benefits from its proximity to the Northeast and Mid-Atlantic markets, two regions that are major gas consumers.

Producers with acreage in the core of the Bakken Shale can turn a profit with crude oil prices around $60 per barrel and generate substantial internal returns when oil trades above $100 per barrel. Parts of the Bakken also contain a second oil-bearing formation, Three Forks/Sanish, which offers additional upside to production. Over the past two years, the number of rigs actively drilling in North Dakota has almost tripled. Statoil’s acquisition of Brigham Exploration, a leading operator in the Bakken, likely won’t be the last deal in this play. For more details on the Bakken Shale, see Bakken Bits from the Dec. 23, 2011, issue of The Energy Strategist.

Located in southern Texas, the Eagle Ford Shale comprises three distinct windows: The northernmost reaches produce crude oil; the central part produces NGLs and gas; and the southernmost portion contains mainly dry gas. To date, much of the development in this play has occurred in the NGL- and oil-rich windows, where early movers enjoy returns on investment that rival or exceed those in the Bakken.

Petrohawk Energy drilled the first discovery well in the Eagle Ford shale and amassed substantial acreage in the core of the play; these assets were likely the primary driver behind BHP Billiton’s acquisition of the company in July 2011.

Although the Permian Basin has been in production since the 1920s, this region in western Texas and southeastern New Mexico has been revitalized by modern drilling techniques and offers low-risk drilling opportunities in a number of oil- and gas-bearing formations. We profiled the Permian Basin at length in Big Perm from the issue Yes, We Shale.

Without further ado, here are my top takeover candidates in North American shale plays.

Oasis Petroleum (NYSE: OAS)

Growth Portfolio holding Oasis Petroleum, which also appears in my Best Buys list, is The Energy Strategist’s top takeover pick for 2012.

Oasis Petroleum offers pure-play exposure to the Bakken Shale and boasts more than 300,000 net acres that are prospective for Bakken Shale and the Three Forks trend. Management estimates that the company has 1,303 potential drilling locations in the Bakken Shale alone. As efforts to develop and prove the productivity of the Three Forks/Sanish formation progress, the firm could add another 1,200 low-risk drilling locations to its inventory. At the end of the third quarter of 2011, Oasis Petroleum’s output averaged 11,500 barrels of oil equivalent per day, 92 percent of which was oil.

At the time of its acquisition by Statoil, Brigham Exploration held about 375,000 net acres in Bakken Shale and produced an average of 16,000 barrels of oil equivalent per day at the end of the third of 2011. Statoil paid about $285,000 per barrel of oil equivalent production when the Norwegian state oil company acquired Brigham Exploration and assumed its debt.

Applying a similar multiple to Oasis Petroleum’s year-end production of 12,500 barrels of oil equivalent per day, the stock is worth about $36 to $37 per share–a slight premium to the current price.

Another popular valuation metric for rapidly growing E&P firms–enterprise value (equity and debt) to earnings before interest, taxation, depreciation and amortization (EBITDA)–indicates that shares of Oasis Petroleum trade at a slight premium to Brigham Exploration when Statoil acquired the company.

But investors should also consider the scarcity factor and timing. As a first mover in the Bakken, Statoil likely paid a lower price than future acquirers.

Based on Oasis Petroleum’s high-quality assets and strong production growth, management would likely demand at least $45 per share in any acquisition. In such a scenario, the total value of the deal would be well under $5 billion, an easy mouthful for a host of major oil companies.

In 2011 Oasis Petroleum’s capital expenditures totaled $527 million. By year-end, the firm had nine rigs operating in the Bakken and had brought about 63 gross wells into production. At the end of 2011, the firm was drilling seven additional wells and 25 of its wells were awaiting completion

Adverse weather interrupted Oasis Petroleum’s drilling program in late spring 2011, a challenge that many other operators in the region faced. The company’s output declined sequentially in the second quarter to 7,893 barrels of oil equivalent per day from 8,090 barrels of oil equivalent per day. In the third quarter, the firm’s production rebounded to 11,583 barrels of oil equivalent per day.

The company should offer detailed guidance on its 2012 production goals and planned drilling budget when the company reports fourth-quarter earnings in early March. Management has suggested that planned expenditures could reach $850 million, which would imply a substantial increase in drilling activity.

The more Oasis Petroleum grows production and demonstrates the quality of its reserves, the more the firm would be worth in a sale. Oasis Petroleum rates a buy under 38.

Kodiak Oil & Gas (NYSE: KOG)

Kodiak Oil& Gas has an enterprise value of only $2.5 billion and holds about 155,000 net acres near properties held by some of the Bakken’s largest and most experienced players. Thus far, Kodiak Oil & Gas’ well results echo data from Continental Resources (NYSE: CLR) and other operators in the region, a testament to the quality of the company’s acreage.

Like Oasis Petroleum, Kodiak Oil & Gas plans to ramp up its drilling activity substantially in 2012. In 2011 the company spent about $230 million and drilled 73 wells. At year-end, the company operated five rigs in the Bakken. But the company will spend as much as $585 million in 2012 and grow its operated rig count to eight units.

Kodiak Oil & Gas produced about 10,500 barrels of oil equivalent per day in 2011. If you factor in output from acquisitions the firm made in October 2011 and January 2012, the company’s total output increases to roughly 17,000 barrels of oil equivalent per day. Management aims to almost double production to 30,000 barrels of oil equivalent per day by the end of 2012.

With an enterprise value to EBITDA ratio of about 25–double that of Oasis Petroleum–the stock’s lofty valuation is the only factor that keeps it from the model Portfolios. Nevertheless, Kodiak Oil & Gas continues to rate a buy in the Energy Watch List.

GeoResources (NSDQ: GEOI)

GeoResources, which boasts leaseholds in the Bakken Shale and the Eagle Ford, has a market capitalization of only $760 million. The company owns 46,000 net acres in the Bakken, of which it operates 33,200 acres. GeoResources has drilled and completed eight wells in a 25,000-acre block near the border between North Dakota and Montana. In 2012 the firm plans to drill between 23 and 26 gross wells in which it will have a 25 to 30 percent working interest.

Peak production rates for GeoResources’ wells in the region average almost 290 barrels of oil equivalent per day, a rate that offers a 70 percent to 90 percent return on investment with oil at $100 per barrel.  

In addition to Williams County, GeoResources also has about 10,000 acres located in eastern Montana, an area in which EOG Resources and other operators have drilled profitable wells. However, these wells aren’t as prolific as those in the Bakken’s core.

Finally, the company has 11,000 acres in Montrail County, N.D., a region that’s home to some of the most impressive Bakken wells. GeoResources holds an average working interest of about 8 percent in more than 100 wells drilled in this portion of the play.

GeoResources’ 25,000 net acres in the Eagle Ford Shale are located in the play’s oil window. The firm has two dedicated rigs drilling in the Eagle Ford, and its first three wells produced an average of 408 barrels of oil equivalent per day over the first 30 days. At the end of 2011, GeoResources had three additional wells awaiting a fracturing crew and two wells being drilled. The firm plans to drill between 20 and 25 gross wells in 2012.

In 2011 the firm’s capital spending totaled $120 million; with the budget expanding to as much as $223 million in 2012,  level of investment that should enable the firm to grow its output from between 5,000 and 5,500 barrels of oil equivalent per day to between 6,500 and 7,500 barrels of oil equivalent per day. Management expects crude oil output to increase to three-quarter of the firm’s annual production from about two-thirds of its yearly lifting.

With an enterprise value to EBITDA ratio of about 5.8 percent, shares of GeoResources are considerably cheaper than Oasis Petroleum or Kodiak Oil & Gas–likely because its acreage isn’t attractive. The company also has more than $200 million remaining on its credit line and no outstanding debt.

Further drilling results from other producers in the Bakken and Eagle Ford could provide a catalyst for the stock before the company releases its own fourth-quarter results on March 13. A speculative bet suitable for risk-tolerant investors, GeoResources joins the Aggressive Portfolio as a buy under 32. Note that I will keep a tight leash on this stock and don’t plan to make it a long-term Portfolio holding.

Whiting Petroleum Corp (NYSE: WLL)

Denver-based Whiting Petroleum Corp operates in five major oil- and gas-producing regions of the US: The Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan. Crude oil accounts for more than 80 percent of the firm’s proven reserves, much of which is concentrated in the Rocky Mountains and the Permian Basin.

The most exciting prospect within Whiting Petroleum’s Rockies acreage is the company’s 680,000-acre leasehold in the Bakken Shale and Three Forks formation. In fact, the firm in 2011 devoted more than half its $1.7 billion budget for capital expenditures to the region.

Whiting Petroleum has de-risked some of its leasehold in the Bakken Shale, primarily in the more established Sanish and Parshall fields, where the company was one of the first movers about five years ago. Both plays continue to produce stellar well results. For example, in the fourth quarter of 2011, the company sank wells in these fields that yielded initial production rates as high as 2,893 barrels of oil per day.

The company’s 111,354 acres in the Pronghorn play and 139,551 net acres in the Lewis and Clark region, two areas south of the Bakken’s core, have shown promise in their developmental stage.

Although an average initial production rate of 1,192 barrels of oil per day and an average 30-day production rate of 523 barrels of oil per day pale in comparison to the gaudy numbers achieved in the Bakken’s core, these wells still yield high returns on investment and will enable the company to grow its reserves.

Whiting Petroleum’s operations primarily rely on pumping carbon dioxide into mature fields to re-pressurize these reservoirs and bolster production. Some of the firm’s acreage in the Permian Basin could benefit from horizontal drilling. In the fourth quarter of 2011, Whiting Petroleum sank four horizontal wells in the Wolfbone area. The first of these wells yielded an initial production rate of 336 barrels of oil per day, on par with other results in the region.

Whiting Petroleum’s enterprise value clocks in at more than $7 billion, which limits the company’s potential suitors to the major international oil companies. The firm boasts one of the best positions in the Bakken Shale and its leasehold in the emerging Niobrara field in the Rockies could also entice acquirers. Whiting Petroleum Corp rates a buy in the Energy Watch List.

Subscribers may recognize Whiting Petroleum as the sponsor of Whiting USA Trust I (NYSE: WHX), which rates a sell in the Energy Watch List. (See the Nov. 23, 2011, issue, Royalty Trusts: Buys and Sells.)

In mid-December 2011, Whiting Petroleum filed an S-1 registration statement with the Securities and Exchange Commission for a second trust imaginatively dubbed Whiting USA Trust II. This will likely trade under the symbol “WHZ,”  and the prospectus suggests that the trust will have its initial public offering by May.

The first draft of the S-1 registration statement has a lot of holes–for example, Whiting Petroleum hasn’t finalized the trust’s projected distributions. The structure could also changes in coming months. More important, we have no idea whatsoever how the trust will be priced at its initial public offering.

But the trust’s basic structure appears compelling. In particular, the trust will be entitled to receive 90 percent of net profits from wells drilled in 49 fields covered by the trust. About 80 percent of the trust’s underlying production will come from wells in the Rocky Mountains and Permian Basin. Oil should account for 73 percent of the trust’s product mix, while natural gas is expected to contribute 24 percent of production. NGLs will account for the remaining 3 percent.

The trust will terminate automatically on Dec. 31, 2021 or once the underlying properties have yielded 11.79 barrels of oil equivalent. If the trust reaches this production milestone before 2021, the structure includes a mechanism that gives unitholders the right to additional cash flow. We will track the trust’s subsequent filings and will issue a rating after the initial public offering.

A pure play on the Permian Basin, Concho Resources (NYSE: CXO) boasts more than 522,000 net acres and 8,700 drilling locations in the region and flowed an average of about 68,600 barrels of oil equivalent per day in 2011. The company is among the most active operators in the Permian, with a total of 31 rigs drilling in its acreage.

Oil production in the Permian Basin peaked at more than 2 million barrels of oil equivalent per day in 1973 and declined at an average annualized rate of 3 percent from 1973 to 2007. Even when production bottomed at about 850,000 barrels of oil equivalent per day in 2007, the Permian Basin remained one of the nation’s top oil fields. Over the past five years, Concho Resources and other producers have breathed new life into the region by using horizontal drilling and hydraulic fracturing. This uptick in activity has reversed the play’s slow decline and led to average annual production growth of about 2 percent.

Concho Resources holds acreage in many of the Permian Basin’s most promising sub-regions. Roughly 57 percent of the firm’s production comes from the New Mexico Shelf, and management has allocated about 40 percent of the company’s $1.25 billion drilling budget to the region for 2012. The company acquired this acreage via acquisitions in February 2006 and October 2010 and primarily targets the Yeso and Abo plays.

Thus far, Concho Resources has drilled vertical wells that cost roughly $1.6 million apiece, take 10 days to drill and yield initial production rates between 110 and 140 barrels of oil equivalent per day. These results pale in comparison to wells in the Bakken Shale, but these long-lived wells and predictable drilling results have enabled Concho Resources to grow production from this area at an average annual rate of 39 percent since 2007. These inexpensive wells also produce high rates of return in the current environment. Horizontal drilling in this region could unlock even more hydrocarbons.

Concho Resources’ activity in the Texas portion of the Permian Basin focuses on the prolific Wolfberry Trend. With 18 rigs operating in this area, the company expects to complete about 400 wells in 2012. Whereas the typical well in many unconventional fields costs upward of $5 million, Concho Resources’ Wolfberry wells cost $1.6 to $1.8 million and take between 15 and 19 days to drill. These wells usually feature between eight and 10 fracturing stages and yield initial production rates of 95 to 125 barrels of oil equivalent per day. These production rates may not be the sexiest, but these cheap wells offer high returns on investment.

With 1,500 identified drilling locations, the company is also one of the largest operators in the Delaware Basin portion of the Permian. In this area, the firm uses horizontal wells with eight to 13 fracturing stages to extract oil and gas from the Bone Springs and Wolfcamp formations. These wells cost between $5 and $7 million to bring into production but yield initial production rates of about 1,000 barrels of oil equivalent per day. In the third quarter of 2011 alone, production from the firm’s Bone Springs acreage surged 59 percent from the prior quarter. Concho Energy rates a buy in the Energy Watch List and could be an attractive takeover target if investors continue to favor names with exposure to higher-profile shale plays.