Marcellus Midstream

The new buzz in the shale-gas sector is Marcellus midstream. Producers may have to time their drilling to chase new midstream facilities. But luckily, the pipelines, processing and storage builders and operators are poised for action as E&Ps continue to see upside value in the dry gas and liquids-rich sections of the Marcellus.

In fact, liquids are moving to the forefront of discussions as oil continues to trade at a substantial premium to gas, 16-to-1 at press time. Yet, obstacles litter the yellow brick road to riches. Although Northeast markets eagerly consume propane, there is a noticeable lack of demand for ethane, and the play’s production is just this side of the level needed to drive new fractionating and liquids takeaway construction.

Also, producers, builders, operators and capital-providers do not agree as to what is needed, and where. For example, Alan Armstrong, president of Williams Cos. Midstream Gathering & Processing, would like to see a change in the way new infrastructure is planned in the shale plays, and says the Marcellus is a good place to start. Armstrong leads Williams’ midstream businesses in Canada and the U.S., and serves as a board member and the chief operating officer for Williams Partners LP.

“Today, gathering is picked up by individual producers or small midstream companies,” he says. “They build one gathering system to connect to a transmission line to get to the closest available market. The problem is, when that pipeline is saturated, producers’ netback begins to fall.”

Spectra Energy’s pipe-stringing operations in Franklin County, Pennsylvania, are part of its Texas Eastern Transmission Pipeline TIME II project, in Ohio and Pennsylvania, to bring up to 150 MMcfd of gas into the New Jersey market area.

A better plan would be to flow gas to a hub with large takeaway lines, he advises. (Williams built Opal Hub, the first gas trading hub, in western Wyoming in the mid-1980s.) After producers pay for gathering, processing and transportation to the hub, they can sell into a competitive daily market to get the best price. Also, should a pipeline outage occur, producers can switch to another and keep gas moving.

“A hub would also allow blending of rich, dry and contaminated gas to meet pipeline specifications at a lower cost. That has yet to play out, but it is certainly what we would like to bring to the Marcellus. In the past, there hasn’t been enough production from the Devonian shale to make that productive.”

When a production field is rapidly developed, such as the Marcellus shale play, growth issues can retard the resource from meeting its maximum potential as quickly as it otherwise would, says Alan Armstrong, president of Williams Cos. Midstream Gathering & Processing.

Armstrong suggests a hub could be sited where a convergence of large transmission lines already exists, such as the Leidy storage facility in northern Pennsylvania.

“Today, that is more of a market-area hub than a supply hub, but it could become both. A southern hub would also make sense with Transco’s planned Keystone Connector pipeline and with Dominion, Texas Eastern, Equitable and Columbia Gas pipelines converging in the southwestern Pennsylvania area. Or, the Marcellus might have two hubs, one each in northern and southern Pennsylvania,” he says.

Williams is a good candidate to build a Leidy hub because it operates the venerable Transco pipeline system. Transco starts in south Texas, moves gas from onshore and offshore Gulf of Mexico gathering, then travels along the eastern seaboard to terminate in New York City. It is the largest single pipeline system (by volume) in the U.S., transporting some 8.6 billion cubic feet per day (Bcfd).

Yet, given the success of the Marcellus, will Transco continue to move Gulf-based gas to the Northeast?

“That’s a good question,” says Armstrong. “It is somewhat dependent on the timing of the Marcellus resource base. It is yet to be seen how much Marcellus gas can supply the Northeast markets. I don’t expect our portion of the production to completely displace southern gas, but overall, the Marcellus has the potential for backing down the need to bring up gas from the Gulf of Mexico, if drilling and production is dramatically accelerated.”

Before it can be accelerated, and the play’s potential fully exploited, the industry must overcome the lack of comprehensive infrastructure and address state and landowner issues, community issues and stakeholders’ concerns in an agreeable manner, Armstrong says.

“When a production field is rapidly developed like this, those issues can retard the resource from meeting its maximum potential as quickly as it otherwise could,” he says. “For now, production is being connected to the 2.8-Bcfd Leidy line which provides access to the Leidy Hub, where Transco has some 100 Bcf of storage.”

The Leidy was originally designed to provide Transco shippers with connections to significant market-area storage, flowing excess production into storage during the summer and then reversing and supplementing traditional supplies during the winter to serve New York and surrounding markets. It wasn’t initially designed to serve Marcellus gas, but has become a fortunate placement for Williams.

MLPs and JVs
In addition to its Marcellus plans, Williams is an old hand at forming MLPs. Its first, Williams Energy Partners (now Magellan Midstream LP), was formed in 2001 and sold in 2003. The company then created the midstream-focused Williams Partners LP (WPZ) in 2005 and the interstate gas-pipeline-focused Williams Pipeline Partners LP (WMZ) in 2007.

Recently, Williams completed a $12-billion restructuring that transformed Williams Partners into one of the largest energy MLPs in the country. Williams contributed most of its interstate gas-pipeline and midstream assets to Williams Partners in exchange for $3.4 billion in cash and 203 million Williams Partners units. The exchange boosted Williams’ ownership of Williams Partners to 84%.

“The new Williams Partners is now much larger than the old WPZ,” says Armstrong. The restructuring increased the partnership’s size and interests to a comparable level with Kinder Morgan, Energy Transfer Partners and Enterprise Product Partners. “This strategy gives us better cost of capital due to scale. Because it is investment grade, we are able to issue debt at a lower cost.”

Williams Partners now owns 100% of the Transco system, plus interests in Northwest Pipeline (65% as of March 1) and Gulfstream (24.5%). The partnership’s large-scale midstream assets are concentrated in major producing basins in Colorado, New Mexico, Wyoming, onshore and offshore the Gulf of Mexico, with a growing presence in the Marcellus shale. There, Williams will fund, begin construction and own the Springville Gathering System. The 28-mile, 20-inch, 375-million cubic feet per day (MMcfd) high-pressure line will move Cabot Oil and Gas production from Susquehanna County in northern Pennsylvania to the Leidy lateral.

Dominion Transmission Inc.’s Hastings fractionation facility in Pine Grove, West Virginia, separates rich Marcellus gas liquids into propane, butane, ethane, natural gasoline and other liquids that are shipped to markets by pipeline, train, barge or truck.

Last year, Williams formed a joint venture with Atlas Pipeline Partners. The project, named Laurel Mountain Midstream, operates a gas-gathering system serving producers in southwestern Pennsylvania. Some of the gas comes from older, rapidly depleting Devonian shale wells, which are being replaced by growing Marcellus production.

The JV has long-term commitments that include nearly all of Atlas Energy’s Marcellus production—one of the top-five acreage holders in the play. Williams initially owned 51% of the Laurel Mountain joint venture, but its ownership interest was transferred to Williams Partners as part of the restructuring transactions.

Elsewhere in the Marcellus, Williams Partner’s Transco entity plans to build the Keystone Connector pipeline as a joint venture with Dominion. The line will run though Atlas assets in southwestern Pennsylvania and terminate at an interconnection with Transco in southeastern Pennsylvania. The schedule for that has yet to be nailed down.

Meanwhile, Williams’ E&P business unit formed a joint venture with Rex Energy, capturing assets along the Marcellus trend line at the northern border of Atlas’ acreage. The Laurel Mountain system will serve that new production as more wells are drilled. Williams also plans connectors to other pipelines that will move gas for its other customers along with its E&P business unit.

“The Marcellus holds great promise for the economies of Pennsylvania and West Virginia,” says Armstrong. “If I lived in either of those states, I’d be excited to watch the job growth for years to come. It won’t be a flash in the pan. This play will be growing for the next two decades, and even in its decline it will still require a lot of manpower to manage the wells and infrastructure.”

He points out that the opportunity is less certain for New York due to differences of opinion on water resources and hydraulic fracturing. “Until those rules get settled, it will be awhile before the opportunity there is developed.”

Right place, any time
Although the shale play is considered to be new and growing, it’s important to remember that U.S. oil production began in Pennsylvania. And at least one large-cap midstream operator has been in the area for quite some time with legacy assets. With regard to the shale play, its pipeline-placement is now more a matter of “right place, any time,” as opposed to a savvy forecast made 60 years ago.

Houston-based Spectra Energy Corp.’s principle asset in the Marcellus is its 1940s-era Texas Eastern pipeline. Designed to move gas from the Gulf Coast to high-demand markets in the Northeast, including New York and New England, the Spectra Energy Transmission-owned-and-operated line runs north through Ohio, then west across Pennsylvania. The 9,200-mile, 6.7-Bcfd system includes 75.1 Bcf of storage capacity.

The Texas Eastern pipeline, a 9,200-mile, 6.7-Bcfd transmission system “cuts right through the heart of the Marcellus shale play,” says Bill Yardley, group vice president, for Spectra Energy, Northeast Transmission.

“It cuts right through the heart of the Marcellus shale play,” says Bill Yardley, group vice president for Spectra Energy, Northeast Transmission. “It’s well-positioned in the sweet spot in southwestern Pennsylvania and northern West Virginia. That’s one of the two big areas of development—the other being the northeast corner near New York.”

The fee-based system hooks up to Spectra Energy’s Algonquin Gas Transmission pipeline, a 1,120-mile, 2.44-Bcfd system that serves New England, New York, New Jersey and Boston. By accessing both pipelines, producers’ gas can reach virtually all East-Coast markets.

Not one to rest on its laurels, the company recently entered into agreements with three shippers to transport gas to New York City via its New Jersey-New York Expansion Project. Says Yardley, “This project will be achieved through expansion of both our Algonquin and Texas Eastern systems and will be fed by El Paso’s Tennessee Gas Pipeline (TGP) in Pennsylvania. This is a great way to participate in the northern part of the Marcellus.”

TGP has announced its Northeast Upgrade project to provide 636 million a day of additional capacity from its 300 Line in Pennsylvania to an interconnect in New Jersey, with most of the capital spending to take place in 2013.

Going forward, Spectra Energy’s first Marcellus project will be the Texas Eastern Appalachia to Market expansion (TEAM 2012). The 200 MMcfd expansion is expected to be turned on in late 2012. The midstream operator signed a binding agreement with an affiliate of Range Resources Corp., one of the early pioneers in the play, to ship a minimum of 150 MMcfd into eastern markets.

“We will file with FERC later this year and start construction in 2012,” says Yardley. “We will follow TEAM 2012 with the TEAM 2013 expansion, an additional 500-MMcfd capacity expansion. Our hope is to continue this expansion program, with one new TEAM expansion each year,” he says.

Yardley is confident the producers are satisfied with the phased-in approach, based on the results of the recent TEAM 2013 open season, which received “an overwhelming response,” he says.

Yet, the company finds it must consistently fine-tune its model as its shippers’ needs evolve. It evaluates the service it provides to each producer in order to provide a custom fit. To better serve its Marcellus shippers, Spectra Energy opened a Pittsburgh office in 2009.

“We need to understand whether they simply want to get into the pipeline, or if they want to take their supply all the way to Boston or New York,” Yardley explains. “We then have to determine how that requirement fits with our portfolio and the best way to meet their needs. Even keeping up with the volume of requests for interconnects is a challenge. But it’s a great problem to have.”

Yardley points out that, as the Marcellus continues to grow, producers can access storage and other markets through the Ontario hub, if need be, noting that it is another accessible “spoke in Spectra Energy’s wheel of gas transmission infrastructure.”

Spectra Energy owns Union Gas, a local distribution company based in Ontario with service in Ontario, Quebec and the U.S. It owns and operates several depleted-reservoir storage pools, including 160 Bcf of capacity at the Dawn storage hub and facility in southern Ontario, just over the U.S.-Canada border near Detroit. That facility includes a massive header line that connects to multiple pipelines.

Spectra Energy’s versatile TEAM-expansion projects allow producers to decide which project best fits as their production grows. Construction should begin in 2012.

Spectra Energy’s storage assets in the Northeast are another strategic piece in its asset portfolio, including 143 Bcf of capacity through its interests in the Leidy (25%) and Oakford (50%) storage fields. The company has a 50% interest in the Steckman Ridge 12-Bcf storage facility that came online in 2009.

The variety of Marcellus gas characteristics poses its own set of challenges for Spectra Energy and for its clients, the producers. Some gas volumes can be delivered immediately into the sales-gas stream, while other gas must be processed prior to transportation.

Ethane production
“We are in the middle of a gas quality discussion with producers and end-users like the local distribution companies. Most of the pipeline tariffs were crafted decades ago, and were just not meant to address a number of the issues being faced today, particularly with CO2 and ethane. The industry is wrestling with this and will have to reach consensus on what these specifications should be.”

With regard to ethane takeaway, Yardley says, “I think people are starting to consider dedicated ethane-takeaway pipelines to Sarnia, Carthage or New Jersey—areas where the ethane can be used. It’s an expensive proposition, but the quantity of ethane that has to be sent out will drive the need for a pipeline.”

“There is no market for ethane in the Northeast,” says Paul Ruppert, senior vice president for Richmond, Virginia- based Dominion Transmission Inc.

“There is no market for ethane in the Northeast,” agrees Paul Ruppert, senior vice president for Richmond, Virginia-based Dominion Transmission Inc. Historically, that has not been a problem on the Dominion system because nearly all the ethane removed is re-injected into the sales-gas stream, or tail gas. The reinjection meets the Btu-per-standard-cubic-foot tariff limits on the outlet specifications.

However, some recent Marcellus production has ethane content too high for it to be left in the tail gas and still meet tariff gas-quality specifications. For now, pipeline operators have issued waivers to producers so they can ship off-spec gas.

Solutions have been proposed, including a new-build pipeline to take the ethane to markets in the South. But that option is not a short-term solution, notes Ruppert.

“In the near-term, some are dealing with the issue by blending high-Btu, ethane-laden gas with low-Btu gas,” he explained. “And some pipelines have granted selected waivers of gas quality for a period of time. However, neither is a reliable or long-range solution. We believe a long-term solution is going to be required, and that producers will become increasingly supportive as the magnitude of the problem and the required solution become clearer.”

The Marcellus shale gas play is a great opportunity for Dominion, he says. “Our workforce in the area is trained and talented. Having the midstream assets already in place is a good starting point from which to build.”

Dominion’s Northeast transmission system, comprised of some 3,500 miles of pipeline, runs from Virginia, West Virginia, Ohio and Pennsylvania into upstate New York. The operator’s midstream system gathers gas, extracts heavy hydrocarbons and moves sales gas to market.

“The system is right in the footprint of the Marcellus, creating synergy for the Marcellus shale-gas producers. We’ve built more than 3,000 miles of gathering lines there, serving both the wet, high-Btu gas and the dry, low-Btu gas streams,” says Ruppert.

Dominion’s liquid-extraction plants, connected to high-Btu gas gathering, are in West Virginia. “We’ve recently announced our Gathering Enhancement Project to expand our West Virginia gathering system and will include additional extraction facilities,” he says.

The Gathering Enhancement Project will reduce pressures in the gathering system and increase Dominion processing capacity to 280 MMcfd from 230 MMcfd. It will also increase fractionation capacity to 560 million gallons per day. The $253-million project is expected to be completed by the fourth quarter of 2010.

Dominion has also proposed the $600-million Appalachian Gateway Project, which is designed to lessen the bottleneck that is preventing some of the gas produced in West Virginia and southwest Pennsylvania from getting to customers in the Northeast. The project will provide over 480 MMcfd of firm transportation for new Appalachian supplies, and is fully subscribed by Appalachian producers.

Dominion plans to add 17,000 horsepower of compression, and 110 miles of new transmission pipeline. Construction is scheduled to begin in 2011, with service commencing in 2012.

The $22-billion market-cap company’s hub-and-spoke transmission system includes an underground gas storage system—the largest in North America—including storage facilities in West Virginia, Pennsylvania and New York.

“At Dominion Transmission, we operate 17 storage pools in the Marcellus Appalachian Fairway. Dominion transmission operates 760 Bcf of underground storage capacity. Including our affiliate, Dominion East Ohio, the company operates more than 900 Bcf of capacity,” says Ruppert.

All of Dominion’s storage fields are developed from depleted sandstone and reef formations among the most prolific gas plays in the Appalachian Basin. “We are fortunate to have storage pools with both good containment and deliverability,” observes Ruppert. “We know when we place gas in these reservoirs, they will hold it in place and release it back to the market at acceptable rates to meet wintertime peaking needs.”

Each of Dominion’s storage fields operates at different pressures, as high as 5,000 psi and as low as 500 psi. “So we have both base-load and peaking pools, depending on the characteristics of each facility. We operate all the facilities as an integrated system,” he says.

Today, Dominion’s gas storage is fully subscribed. “We think there is a great opportunity for new storage development. We are always looking to grow our assets. And we’d welcome the opportunity to grow our gas storage business.”

Business model
”The company’s business model, to link new gas supply to market, is the same tried-and-true strategy it has employed for years,” says Ruppert.

“For example, with our Dominion Hub I Project, we were the first company to contract with customers to build a takeaway project from the Rocky Mountain Express (Rex) pipeline at Clarington, Ohio, to Dominion’s transmission system. The Northeast is an area of high energy consumption,” he says. “Customers value the diversity of supply we make available to them.”

In fact, the region has access to Canadian gas, conventional and unconventional Appalachian production, Rex gas and liquefied natural gas (LNG) from the Chesapeake Bay. Such diversity ensures reliable, competitive supplies for Northeastern consumers. Despite the gas-on-gas competition, the region continues to be a premium market with high demand that producers seek to access.

Dominion’s business model led it to acquire the Cove Point LNG re-gasification terminal, sited on the Chesapeake Bay in Lusby, Maryland, just south of Baltimore. After the purchase from Williams Cos. on Sept. 5, 2002, the import service was reactivated. Dominion expanded that facility, nearly doubling its size to 1.8 Bcfd of send-out capacity and 14.6 Bcf of storage held in seven above-ground tanks.

“Our strategy has ensured that we will always be well-positioned to get new supplies to market,” states Ruppert. “That model drives new infrastructure, and we certainly like to build infrastructure, especially in the Northeast and mid-Atlantic.”

Dominion’s transmission business is a regulated service provider and its model has a bias for reservation rates such as those typically approved by FERC. This is reflected in its transportation and storage contracts where customers are charged for each dekatherm of capacity reserved, whether used or not.

“In contrast, on the gathering and processing side, for several years we have followed a model where rather than charging a fixed or variable fee for our service, we retain gas in-kind,” he explains. “That retention can be compared to a percent-of-production fee.”