Encana, several other producers developing Collingwood shale

Several E&P companies, including Canada's Encana Corp. are moving forward with plans to develop yet another unconventional resource play — the Collingwood shale in Michigan. Encana, along with Atlas Energy and Breitburn Energy Partners, have been quietly acquiring acreage in the Collingwood for several years. Quicksilver Resources owns about 33% of Breitburn.

Over the past two years, Calgary-based Encana has assembled a significant land position on the promising new natural gas shale play located in several different counties in the Lower Peninsula of Michigan. The company's first exploration well, drilled by Encana subsidiary Petoskey Exploration LLC, based in Denver, delivered encouraging test results. It is a 5,000-ft horizontal penetration that targeted the Collingwood shale at 9,500 feet true vertical depth. Petoskey's Pioneer 1-3 is in 3-24n-7w, Missaukee County, 30 miles southeast of Traverse City.

"Natural gas is being produced primarily from the Collingwood shale, with contribution from the overlying Utica shale," Encana said. "With further drilling we hope to demonstrate stronger gas rates as we optimize well completion practices and prove up rich liquids potential in some parts of the play."

Collingwood, a shaly limestone about 40 feet thick, lies just above the Ordovician Trenton formation. The Michigan basin extends into Ontario, Canada, where oil and gas regulators were said to be studying its potential.

Encana has acquired about 250,000 net acres of land on the Collingwood shale play at an average cost of about $150 per acre, well below prices paid at the state's most recent land sale in early May 2010.

"In keeping with our approach of quietly assembling large land positions on promising unconventional natural gas plays, our substantial Michigan shale position has the potential to add meaningful future resources and production to our North American portfolio of prolific resource plays," said Randy Eresman, Encana's president and CEO.

"Our first well flowed during a 30-day initial production test at about 2.5 million cubic feet per day, including natural gas liquids constituents and condensate," Eresman added. "With further drilling we hope to demonstrate stronger gas rates as we optimize well completion practices and prove up rich liquids potential in some parts of the play. It's too early to know the economic potential of this new Collingwood shale play, but we plan to drill additional exploration wells this year that will help determine the play's ultimate potential."

Atlas Energy has acreage in the region in what it calls the "Collingwood Utica Shale." The Utica Shale is also present at a shallower depth on the acreage. Atlas has 70,000 net acres exposed to the Collingwood Utica Shale, and has 83% of the leases held by production.

BreitBurn Energy Partners L.P. 470,000 net acres in Michigan, and believes that 90,000 net acres are prospective for the Collingwood Utica Shale. The company also has much of its acreage held by production. BreitBurn owns significant infrastructure all over Michigan, including pipelines, compression facilities, and gas gathering lines.

The industry excitement over the Collingwood/Utica Shale can be seen in the results of a recent auction by the State of Michigan of oil and gas rights in the state. The sale netted $178 million in bonus payments for the state, the highest ever, breaking the record of $23.6 million set in 1981.

The average price paid for acre in the auction was $1,507 per acre, up from $26 per acre in previous auctions. The highest price paid was $5,500 per acre.

The Collingwood Shale is not the only shale in Michigan, as the industry has been exploiting the Antrim Shale for many years. The formation has produced more than 2.6 tcf of gas since development began. — Don Stowers

Total E&P spending to rise 8% in 2010; oil service costs likely to escalate following Deepwater Horizon incident

Spending on exploration and production, excluding acquisitions, is expected to rise by 8% to $353 billion in 2010 among more than 110 of the largest publicly traded oil and gas companies, according to the IHS Herold 2010 Global Upstream Capital Spending Report. An initial IHS Herold study of 65 companies issued in February had predicted a 7% increase.

"This is a nice turnaround from the 22% decline in upstream spending in 2009, when the global recession and tight credit markets made companies rein in upstream spending," said Aliza Fan Dutt, senior equity analyst at IHS Herold. "The market conditions have improved, which is reassuring, and WTI (West Texas Intermediate) prices have hovered between $70 and $80 per barrel during the past few months. Steadier oil prices, combined with continued uncertainty over the near-term outlook for natural gas prices, are driving some E&P's to shift their focus from gas to oil," she said.

"However, this shift comes with a caveat," she added, "since following the explosion and oil spill in the Gulf of Mexico, there is growing uncertainty in the industry over possible changes in government regulations and taxation relative to oil and gas drilling. As a result, we expect some shifts in E&P spending from deepwater to onshore US and, to a lesser extent, overseas plays, due to increased risks associated with drilling in the deepwater Gulf of Mexico. In addition, the uncertainty over the causes of the Deepwater Horizon oil blast and government restrictions on deepwater drilling will dampen activity in the US offshore waters."

While the potential long-term impact of the Deepwater Horizon incident on E&P capital spending will not be known for some time, Dutt said, "regulatory and safety requirements will be heavily scrutinized, which will likely translate to higher oil service costs. These higher operating costs, and, hence, increased capital spending, will likely occur gradually, though, over an extended period of time."

Shift to liquids production

Despite the situation in the Gulf, the report says that most E&Ps are touting their exposure to liquids production. Many natural gas-focused producers are shifting to oil drilling or are highlighting their exposure to liquids-rich unconventional gas. "Conventional gas development is being severely cut back," Dutt said, "while prolific shale gas plays such as the Marcellus and Haynesville continue to drive spending among many E&P companies."

Decreased spending in the last couple of years meant a decline in demand for equipment, which translated into oil field service costs that are now about 15% to 20% below the peak prices and demand of 2007-2008. Lower oil service costs should help oil and gas companies stretch their dollars even further, although, with increased upstream spending this year, rig prices could increase, which means producers must spend more as this year progresses in order to keep up with reserve replacement rates, the report noted.

Capital spending rebounds in 2010

According to the report, the combined Integrated Oils Peer Groups cut capital spending by 14% in 2009, due in large part to big cuts by the North American integrated oil companies. However, spending by the integrated oil companies is expected to rebound 5% in 2010. And after being slashed nearly 40% in 2009, capital spending by E&P companies is slated to jump 21% in response to higher oil prices and the need to increase production. An improved credit market has helped small US E&Ps increase capital spending, and the largest North American E&Ps are looking to boost spending by a healthy 24%.

More economical gas shale plays and liquids continue to be red-hot, driving much of this year's upstream spending for this group. Particularly attractive are shale plays that yield significant oil and liquids, such as the Eagle Ford shale play in south Texas.

Slammed by the nearly non-existent credit market last year, small US E&Ps slashed capital spending by 61% in 2009. "What a difference a year makes," Dutt said. "The improved economy has opened up new sources of capital, which should result in a 62% increase in spending for these small companies, which is the most dramatic rise in spending among all peer groups."

Global integrated oil companies, representing about 28% of the total spending among companies in the IHS Herold study, are expected to cut capital spending by a modest two percent in 2010. However, the integrated companies outside North America are expected to increase capital expenditures by 12% in 2010 on stronger spending in Russia, Latin America and Asia. Offshore development will fuel a 23% increase in spending at Petrobras.

After falling by 26% in 2009, upstream spending among the US integrated oils is slated to rise 13%, primarily due to brightening prospects in the North American upstream. Hess plans to boost spending by 26% in 2010, much of which will be committed to the Bakken shale play.

Capital budget rationalization from the Suncor/Petro-Canada merger is the primary reason for the expected 8% drop in upstream spending among the Canadian integrated companies. The Canadian E&P Trusts should boost capital spending by 44% this year, a reversal of the 5% decline last year. All companies in this peer group are expected to increase spending.

The only peer group to boost spending in 2009, companies in the E&Ps Outside of North America Group, should increase capital spending by nine percent in 2010. Spending by CNOOC remains strong as it explores in new areas, such as the Philippines and Vietnam.

NOIA, IPAA form new task forces for oil spill preparedness and response

The National Ocean Industries Association (NOIA), Independent Petroleum Association of America (IPAA) and the American Petroleum Institute (API) have formed two new task forces to address oil spill preparedness and response.

"A recurring theme raised by the ongoing spill in the Gulf of Mexico is that the technology exists to drill successfully in deeper and deeper water, but the technology to respond to release of oil in these environments appears not to have kept pace," said NOIA president Randall Luthi.

The task forces will review the ongoing spill response actions both on the surface and subsea and will make recommendations on how to improve future response and containment efforts.

The task forces will seek input from top academics and researchers, state and federal agencies and fellow trade associations, among others. Findings and recommendations will be shared with Congress, the Presidential Investigative Commission, the industry, and the public.

EXCO acquires Haynesville, Bossier assets from Southwestern for $355M

Dallas-based EXCO Resources Inc. has agreed to purchase properties prospective for the Haynesville and Bossier shales from Southwestern Energy Co. for $355 million. The properties include producing assets, gathering lines, and acreage in Shelby, San Augustine, and Nacogdoches Counties, Texas and are located within the area of mutual interest established by the existing East Texas/North Louisiana joint venture with BG Group plc. BG Group will have the opportunity to purchase 50% of this acquisition.

Nearly all of the interest to be acquired is incremental to the interest in the producing assets, gathering lines and acreage acquired by EXCO and BG Group through the acquisition of Common Resources LLC, which closed May 14, 2010. The acquisition will increase EXCO's interest in over 900 gross drilling locations. The assets include producing properties with current gross production of more than 51 Mmcf per day (17 Mmcf per day net) from 9 producing wells and approximately 20,000 net acres prospective for the Haynesville and Bossier shales. Assuming BG Group participates in the acquisition, EXCO and BG Group will each double their working and net revenue interests in much of the Common acreage.

The acreage is situated in the Shelby Trough formation that runs from the southeast corner of DeSoto Parish, Louisiana through southern Shelby, northern San Augustine and eastern Nacogdoches counties, Texas. EXCO's first operated well in this area had an initial production rate of 22.1 Mmcf per day.

Houston-based Southwestern Energy retained the drilling and producing rights covering all other depths in the acreage, including the company's current James Lime and Pettet drilling programs.

Southwestern will continue an active drilling program in East Texas, which includes approximately 10,500 additional net acres under which it believes that the Haynesville and Middle Bossier Shale intervals are prospective. The company is currently drilling its second Haynesville/Bossier well in this acreage and expects initial production in the fourth quarter upon the completion of pipeline infrastructure.

As a result of the sale, Southwestern has revised its capital program in East Texas for calendar year 2010 to approximately $185 million, which includes participating in approximately 35 to 45 gross wells, down from $230 million, which had included 50 to 60 wells.

ExxonMobil officially owns XTO