May 2012, Vol. 239 No. 5

Features

Spectra Sees Shale Gas Strength Despite Pipeline Opponents

The U.S. gas shale boom comes with the challenge of bringing that supply to market when new pipelines face safety questions, but Spectra Energy President and CEO Greg Ebel said the industry should be able to make the case for how gas is beneficial.

A main selling point for gas in the U.S. is to present it as way to replace coal as fuel in the power generation sector because it burns relatively more cleanly, Ebel said on Platts Energy Week, all-energy news and talk show program.

“Just along our pipeline, Texas Eastern, which goes from the Gulf Coast … up into through Ohio, Pennsylvania and ultimately to New York, there are approximately 100 coal-fired plants that were built between 1899, if you can believe it, and 1982,” said Ebel, who is also the 2012 Chairman of the Interstate Natural Gas Association of America (see P&GJ April 2012).

“Over time, those are going to be replaced with cleaner burning and cheaper natural gas, and that’s really driving the biggest growth in the demand of natural gas in North America,” he said.

Asked about spills and explosions in the oil and gas sectors in recent years in the U.S., including the Pacific Gas & Electric San Bruno gas pipeline disaster, the BP Gulf of Mexico oil spill and some oil pipeline spills, and how those raise concerns in the general public, Ebel said a lot of the incidents were in the oil sector, not the gas sector. Still, he added that people tend to conflate the two as simply problems with all pipelines.

So, gas pipeline companies need to demonstrate that their projects can be handled with safety as a primary concern, Ebel said. For instance, Spectra’s proposed New Jersey-New York expansion project on its Texas Eastern Transmission and Algonquin Gas Transmission pipeline systems will be buried deeper than most and exceed current safety standards in the U.S., he said.

The 20-mile pipeline would deliver up to 800,000 Dekathems per day (Dt/d) to New Jersey and New York markets, including a direct connection to Manhattan. Construction and design changes incorporated into the project to address local concerns in these heavily populated urban areas include using 30-inch pipe with thicker walls that required under federal regulations, 42-inch pipe in other segments, and using horizontal direction drilling for its major water crossings and some inland portions.
“The benefits of that pipeline, for example, have come through loud and clear. It’s actually a relatively small pipeline, some 15 to 20 miles, but the cost is significant – over a billion dollars. But, the benefits are far in advance of that,” Ebel said.

A Rutgers University study for Spectra found $400 million in annual benefits for businesses and citizens in New Jersey and New York from the project, if it is built, “because you’ve got bottlenecks that don’t allow cheap natural gas to get to those areas,” Ebel said.

“In a place like New Jersey, with high unemployment, you’re talking about some 5,000 jobs to build this and real energy savings for people,” he added.

Spectra hopes the safety measures and economic benefits presented will win approval for the pipeline project.

“It’s never easy to build anything. But I think we’re done a good job of really working with the communities to make some adjustments to that project and get to the point where… the federal government is about to – we hope – approve its building here shortly,” Ebel said.

Spectra has $7 billion in infrastructure projects under construction or in development. With merger and acquisition activity arising in the gas sector, Ebel was asked whether Spectra would seek to pick up assets. He said there may be acquisition opportunities in regions outside its current footprint.

 “We don’t need to do acquisitions. But as you point out, as these mergers and acquisitions happen, there are usually some selloffs of assets. And, we look forward to participating in those,” the CEO said.

“There are a few areas of the country where we don’t have major pipeline systems and we’ll be looking at those. Fortunately, the company is strong financially and we’ve got the capability given our size if the opportunities present themselves.”
 

ExxonMobil, GE Join University Initiative On Natural Gas Best Practices
Colorado School of Mines, Penn State University and the University of Texas at Austin have announced a new training initiative to support the rapidly growing shale natural gas and oil development sector. The training programs created under the initiative will be led by the faculty at each academic institution and are designed to ensure that regulators and policymakers have access to the latest technology and operational expertise to assist in their important oversight of shale development.

ExxonMobil and GE said they would each contribute $1 million to the educational initiative.

“Regulators have said the need for increased training is one of their highest priorities due to the rapid expansion of shale resource development and the equally active evolution of technologies and best practices in the field,” said Gary Pope, director of The Center for Petroleum and Geosystems Engineering (CPGE) at The University of Texas at Austin.

To meet this demand, CPGE, which provides engineering leadership and technology innovation related to energy and the environment with special emphasis on the production of hydrocarbons from conventional and unconventional sources, added an Education, Training and Outreach Program, directed by Dr. Hilary Clement Olson.
“This funding provides us with the resources to broaden our partnerships and our scope to create a new training program for regulators in the oil and gas industry that is collaborative and interdisciplinary,” said Olson.

Thomas Murphy, co-director of the Penn State Marcellus Center for Outreach and Research, said, “The Shale Gas Regulators Training program affords the university a unique opportunity to further develop shale gas best management practices and to offer new regulators the chance to learn the latest science-based concepts related to geology, petroleum technology and environmental quality. Penn State looks forward to providing development training that will help ensure a strong, yet consistent, regulator process across the Appalachian Basin.”

Colorado School of Mines President M.W. Scoggins said, “Colorado School of Mines’ focused mission to educate the next generation of engineers and applied scientists fosters a natural partnership in this consortium. Our specialized curriculum and research program centered on responsible resource development is helping to enhance global understanding of our most pressing earth, energy and environmental challenges.”

Added Colorado School of Mines’ Dr. Azra N. Tutuncu, who is director of the school’s Unconventional Natural Gas and Oil Institute (UNGI) and Harry D. Campbell Chair in Petroleum Engineering, “The Unconventional Natural Gas and Oil Institute at Colorado School of Mines provides training for developing unconventional resources in an environmentally sound, safe and economically viable manner—the oil and gas industry as well as state and federal regulators and policymakers benefit from this expertise.”
The series of courses, which will primarily focus on the development of shale resources, will cover:
* Petroleum geology, both conventional and nonconventional;
* Petroleum technology, including principles of drilling operations and well design, as well as facility design and operation;
* Environmental management technologies and practices, including water treatment and management, waste treatment and management, air emission control technologies, spill prevention and planning and response; and
* Federal and state oil and gas regulatory requirements, including permitting and reporting, plus compliance assessment.

“America’s shale energy resources are creating jobs and economic growth in regions across the country, and Americans rightly want to know that these resources are being produced safely and responsibly,” ExxonMobil CEO Rex Tillerson said.

GE CEO Jeff Immelt said, “Natural gas is dramatically changing the way we power America, and GE is committed to its responsible development. Advanced technology, an expert workforce and smart regulation are the keys to America leading the world in shale gas development. GE recognizes the importance of minimizing a site’s environmental footprint while simultaneously increasing operational efficiency.”
GE and ExxonMobil note that while hydraulic fracturing, horizontal drilling and other technologies used to produce shale resources are not new, they are being used today on a larger scale than ever before.

Williams Partners Buying Major Stake In Marcellus Shale

Williams Partners L.P. has agreed to acquire Caiman Energy’s wholly owned subsidiary, Caiman Eastern Midstream LLC, for approximately $2.5 billion. The acquisition will provide Williams Partners with a significant footprint and growth potential in the natural gas liquids-rich portion of the Marcellus Shale.

Williams owns 72% of Williams Partners, including the general-partner interest. Caiman Energy is backed by private equity investors including EnCap Flatrock Midstream, EnCap Investments L.P. and Highstar Capital.

Caiman Eastern Midstream is an independent gathering and processing business located in northern West Virginia, southwestern Pennsylvania and eastern Ohio.

Caiman’s existing physical assets include a gathering system, two processing facilities and a fractionator. Expansions to the gathering system, processing facilities and fractionator are under construction. An ethane pipeline is also planned.

The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio and Pennsylvania.

Williams Partners expects significant growth in gathering volumes and NGL production from these assets. There is an estimated 300 (Tcfe) of natural gas in place within a 35-mile radius of the system, and a significant amount remains undedicated. The partnership expects the Caiman system to gather more than 2 Bcf/d and produce approximately 300,000 b/d of NGLs and condensate by 2020.

Joint Venture To Develop Utica Shale Infrastructure
Williams Partners said it also intends to participate in a new joint venture with Caiman Energy and its investors and management to develop midstream infrastructure in the NGL- and oil-rich areas of the Utica Shale, primarily in Ohio and northwest Pennsylvania.

“These new assets, anchored by long-term agreements with a diverse set of customers, give us a major presence in the liquids-rich portion of the Marcellus Shale,” said Alan Armstrong, CEO of Williams Partners’ general partner. “We expect significant long-term growth potential because the liquids-rich gas makes this area the most economical and top-performing play for producers in North America.

“It’s also just adjacent to the rich gas and oil-producing portions of the Utica Shale, where we’re planning on developing new infrastructure with Caiman. Our goal is to be the leading gathering, processing and transportation solution provider for producers in the Marcellus Shale.

“We’re putting together the kind of infrastructure that makes drilling in the Marcellus even more desirable for producers because we provide large-scale infrastructure solutions that connect producers’ natural gas and natural gas liquids to the best markets.”

Jack Lafield, president and CEO of Caiman Energy, added, “We’re pleased that this transaction will achieve a strong return for our investors at EnCap and Highstar Capital. We’re very proud of the sizable rich gas system we’ve built in the Marcellus and the great relationships Caiman has developed with producers and the people of West Virginia. We’re excited to turn over our gathering and processing assets to the Williams team. Williams has a unique ability to build on the value we’ve created in the Marcellus.

“Today also marks the beginning of an exciting new alliance with Williams Partners,” Lafield said. “We’re looking forward to working with Williams in the Utica Shale to bring midstream infrastructure to Ohio for producers working in this dynamic and rapidly evolving play. When you combine our management team and the expertise of both our companies in gas gathering, processing and NGLs, with our shared commitment to community and customer-focused solutions, it’s clear that Caiman and Williams are a powerful team.”

Ohio Producers Fighting Tax-Increase Proposal 
Ohio’s crude oil and natural gas producers, represented by the Ohio Oil and Gas Association (OOGA), are taking a stand against the severance-tax increase proposed by the Kasich administration as part of its mid-budget review. Though the tax-increase provision is currently removed from the bill, the oil and gas industry remains adamant that a tax increase of any kind at this critical juncture in the exploration of the Utica shale formation will diminish Ohio’s business-friendly climate and the economic future of all Ohioans. 

“The specter of a tax increase has induced a sense of uncertainty among oil and gas companies which have to rethink their original business plans for drilling in Ohio,” said Tom Stewart, executive vice president of OOGA. “Ohioans deserve prosperity through growth and this tax proposal has placed that opportunity at risk.” 

With only seven wells producing in two counties, the industry says it is too soon to know the real value and viability of the Utica. The infancy of Utica shale development is one of several points of contention that oil and gas producers have with the administration’s proposal. In addition to concerns about taxing an emerging industry, it takes offense to claims that the severance tax is outdated and far less than other states; that out-of-state companies are taking Ohio’s resources; and that natural-gas liquids are not currently taxed. 

The administration claims that Ohio’s severance tax is 40 years old and needs to be “modernized.” The truth is that the severance tax, like other oil and gas taxes, was reformed only two years prior with the bipartisan passage of SB 165, according to OOGA.

The severance-tax rate doesn’t tell the whole story. While the rate is comparable to or less than those in neighboring states, it’s important to note that crude oil and natural gas producers in Ohio also pay four other taxes: income, sales, commercial activity and ad valorem — a property tax based on the value of unproduced minerals remaining in the ground. 

“Comparing Ohio to other shale-producing states is difficult because of the variations in the tax structure and the incentives and abatements offered,” said Jerry James, president of OOGA and Artex Oil Company in Marietta. “For example, Pennsylvania has no severance or ad valorem tax while West Virginia has a 5% severance tax.” 

James noted that oil and gas drilling has declined in West Virginia in the past five years, while drilling activity has increased 600% in Pennsylvania during the same time period. However, some companies have curtailed activity in the state since an impact fee was imposed. 

The administration has portrayed oil and gas companies as “foreigners” who are coming to Ohio to take its natural resources, which is untrue, James said, noting that Ohio has a 150-year-old heritage of oil and gas production and is home to hundreds of local producers, as well as many out-of-state companies, which plan to invest billions of dollars in Ohio and its workforce. 

He said because Ohio is a large consumer of natural gas, much of the gas being produced will remain in the state as reserves to be used by residents and businesses, particularly those in the manufacturing and chemical industries.

The administration has claimed that there is currently no separate tax on natural-gas liquids — the “wet gases” such as ethane and butane that are highly valued among the chemical industry. While the tax might not be on the books, according to James the industry has been paying taxes, most often at the more costly crude-oil rate.

“Every molecule severed and sold from a well is taxed under the current tax structure,” said James. “If it’s sold in the gas phase, it pays the natural-gas severance rate. If it’s sold as a liquid, it pays the crude oil severance rate.”