As exciting and profitable as new plays are for upstream companies, so goes it for midstream companies. There’s no doubt that development of unconventional oil and gas continues to drive a significant portion of U.S. pipeline construction.

While production from the unconventionals, such as the Marcellus, Eagle Ford, Haynesville, Bakken and Niobrara formations, ramp up to meet rising demand, pipeline companies and midstream operators are making plans for new transportation systems in the midcontinent, southeast, and northeast regions of the country.

By most estimates, multi-billions of dollars will be spent on infrastructure during the next ten years. This year, midstream executives are busily planning the optimal routes for pipelines and the most economical locations for processing and storage. Operators are re-thinking their business models as pipeline managers continue to switch contracts to fee-based services, processors fine-tune tactics for liquids-versus-whole-gas and storage operators create strategies to manage pad gas and cycle services.

One of the most exciting midstream-opportunity areas is the Marcellus shale play in the Appalachian Basin of the northeastern U.S. While most national gas prices continue to hover between lower and lower, the shale gas of Pennsylvania, West Virginia and nearby states continues to command a premium from the profitable New York market.

Marcellus Midstream

The new buzz in Marcellus midstream is that E&Ps continue to see upside value in both 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. New York is a good market for propane, although there is a notable lack of demand for ethane. While some processing facilities exist, 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, according to Alan Armstrong, president of Williams Cos. Midstream Gathering & Processing. He would like to see a change in the way new infrastructure is planned in all of 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.”

A better plan would be to flow gas to a hub with large takeaway lines, he advises. 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,” he says.” 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 240-mile 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.

Dominion Transmission Inc.'s Hastings fractionation facility in Pine Grove, W. Va., 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. (Photo courtesy of Dominion Transmission Inc.)

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 (Bcf) per day.

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.”

Yet, 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.

“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, which plans a growing presence in the Marcellus. It will fund, begin construction and own the Springville Gathering System. The 28-mile, 20-inch, 375-million cubic feet (MMcf) per day high-pressure line will move Cabot Oil and Gas production from Susquehanna County in northern Pennsylvania to the Leidy lateral.

In 2009, 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.

Elsewhere, 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.”

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-Bcf per day system includes 75.1 Bcf of storage capacity.

“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-Bcf per day 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 planned its Northeast Upgrade project to provide 636 MMcf per day of additional capacity from its 300 Line in Pennsylvania to an interconnect in New Jersey, with most of the capital to be spent in 2013.

Spectra Energy's pipe-stringing operations in Franklin County, Pa., are part of its Texas Eastern Transmission Pipeline TIME II project, in Ohio and Pennsylvania, to bring up to 150 MMcf/d of gas into New Jersey. (Photo courtesy of Spectra Energy)

Going forward, Spectra Energy’s first Marcellus project will be the Texas Eastern Appalachia-to-Market expansion (TEAM 2012). The 200 MMcf per day expansion is expected to be operational 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 MMcf per day 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-MMcf per day capacity expansion. Our hope is to continue this expansion program, with one new TEAM expansion each year,” he says.

Spectra Energy has storage assets in the Northeast, including 143 Bcf of capacity through its interests in the Leidy and Oakford 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. Some gas volumes can be delivered immediately into the sales-gas stream, while other gas must be processed prior to transportation.

“We are in the middle of a gas quality discussion with producers and local distribution companies,” says Yardley. “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 the industry has to consider building dedicated ethane-takeaway pipelines to Sarnia, Carthage or New Jersey—areas where the ethane can be used.

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


Spectra Energy's versatile TEAM-expansion projects allow producers to decide which project best fits as their production grows. Construction should begin in 2012. (Illustration courtesy of Spectra Energy)

“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.”

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. 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 MMcf per day, up from 230 MMcf per day. 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 also plans a $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 MMcf per day of firm transportation and is fully subscribed.

Four new compressor stations would be constructed and upgrades would be made at two existing compressor stations, adding about 17,000 horsepower of compression to Dominion’s system. About 110 miles of 20-, 24- and 30-inch pipeline looping would be installed in northern West Virginia and southwest Pennsylvania, terminating at the Oakford station in Delmont, east of Pittsburgh. Construction might begin in 2011 to be in-service in 2012.

The 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. It operates 17 storage pools in the Marcellus fairway and 760 Bcf of underground storage capacity. Including its 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.

Elsewhere, National Fuel Gas Supply Corp. is gauging market interest in its West-to-East expansion project, designed to offer new natural gas transportation capacity from Appalachia and central Pennsylvania to key northeast market interconnects at Leidy. Current plans call for the project to be built in two phases. In Phase I, National proposes to construct pipeline and compression facilities from the area near the intersection of National Lines FM 100 and FM 120 to Leidy. The project includes some 32 miles of 30-inch-diameter pipe and a 7,100-horsepower compressor station. With sufficient market interest, construction could start in late 2010 or early 2011 to meet a tentative November 2011 completion date. Phase II could begin in November 2012 with the construction of an additional 50 miles of 30-inch pipe to run along the existing FM 100 corridor back to National’s Line K area, along with a second compressor station with up to 9,000 horsepower.

Also in the region, Tennessee Gas Pipeline Co. announced plans for its 300 Line Expansion project, designed to link Marcellus and Appalachian production to northeast markets. The expansion facilities include some 128 miles of 30-inch pipe loop and about 46,000 horsepower of compression. The facilities will be constructed in Tennessee’s existing pipeline corridor in Pennsylvania and New Jersey. Tennessee plans to execute phased construction during 2010 and 2011, pending receipt of regulatory approvals.

Eagle Ford Midstream

As oil and gas producers jockey for position in relatively new Eagle Ford shale discoveries, pipeline and midstream companies are increasingly looking to the South Texas play for opportunities to build new infrastructure systems.

Enterprise Products Partners LP is a key player in the region, and it has two new pipeline projects that are expected to provide in excess of 200 MMcf per day of incremental transportation capacity in LaSalle and Webb counties in Texas. These projects are the initial expansions of Enterprise’s comprehensive network of midstream assets in South Texas that will be well-situated to enable Eagle Ford producers to maximize the value of their gas, liquids, condensate and crude production. By combining this new infrastructure with its existing assets, the partnership expects to provide midstream services to more than 700,000 acres in the Eagle Ford, 400,000 acres of which have already been dedicated to Enterprise. With the success and acceleration of drilling programs in the Eagle Ford, Enterprise plans to evaluate more investments in pipelines and processing facilities.

One of Enterprise’s new systems is the White Kitchen Lateral, a 62-mile, 16-inch gas pipeline that runs through the heart of the shale in LaSalle and Webb counties. The White Kitchen Lateral connects two existing lines that lie at opposite ends of the development and are part of Enterprise’s South Texas pipeline system. Some segments of the White Kitchen Lateral are already in service. An additional segment to further expand the capacity of the White Kitchen Lateral is scheduled for completion in 2010, at which time the White Kitchen Lateral is expected to provide more than 200 MMcf per day of incremental capacity to the Enterprise system.

Enterprise recently completed a 34-mile, 24-inch gas pipeline as the first segment of an east-west Eagle Ford mainline. The segment connects the partnership’s South Texas pipeline system in southwest LaSalle County to the White Kitchen Lateral.

“With exploration and production activity in the Eagle Ford ramping up so quickly, it’s essential that midstream infrastructure and services be able to keep pace,” says A.J. “Jim” Teague, executive vice president and chief commercial officer for Enterprise.

“Enterprise recognized the potential of this play early and we have already responded by placing steel in the ground and are developing other projects that will complement our existing integrated network of South Texas assets and could start providing value-added services for producers within a matter of months.”

The Eagle Ford shale gas has natural gas liquids (NGLs) ranging between four and nine gallons per thousand cubic feet of natural gas. These NGLs must be removed before the gas can meet the quality specifications to be moved into pipelines for end-use markets. Currently, Enterprise has seven gas-processing plants with an aggregate capacity of some 1.5 Bcf per day.

Meanwhile, the forecasted NGL production growth is expected to place additional pressure on an already oversupplied NGL market in South Texas. Through Enterprise’s integrated midstream system, mixed NGL production from the Eagle Ford can be fractionated at the company’s Mont Belvieu, Texas, complex and stored or distributed to local or international markets through Enterprise’s export facility. It can also transport mixed NGLs to its South Louisiana facilities for fractionation, storage and distribution.

Also, with its recent acquisition of TEPPCO Partners LP, Enterprise is transporting crude and condensate from the Eagle Ford. Previously, much of such transportation has been by truck. Enterprise is looking into “logistics opportunities” that would enable Eagle Ford oil and condensate to be marketed at the Cushing, Oklahoma, oil-trading hub or the Houston, Texas, area market.

Other pipeline companies and midstream operators are also planning new projects in the region. Kinder Morgan Energy Partners LP and Copano Energy LLC signed a letter of intent for a 50/50 joint venture to provide gathering, transportation and processing services to Eagle Ford gas producers. Under the agreement, the joint venture will construct, as a first phase, a 22-mile, 24-inch gathering system that will originate in LaSalle County, Texas, terminate in Duval County, Texas, and will have an initial capacity of 350 MMcf per day. The pipeline is expected to be completed by year-end 2010.

“This new alliance will provide seamless bundled gathering, processing and transmission services to Eagle Ford shale producers through the combination of our companies’ immediately available pipeline and processing capacities,” says Tom Martin, president of Kinder Morgan’s Texas Intrastate Pipelines. “This new pipeline is the first step to expand our combined network in support of Eagle Ford shale development.”

“Since the inception of Copano’s South Texas business model in August 2001, our commercial alliance with Kinder Morgan has played a key role in the growth of our midstream services business,” adds Bruce Northcutt, Copano Energy’s president and chief operating officer.

Meritage Midstream Services is building 31 miles of 16-in. gathering lines in Webb County, Texas, in response to producers' needs in the emerging Eagle Ford Shale play. (Photo courtesy of Meritage Midstream Services)

Elsewhere, start-up company Meritage Midstream Services is emerging as another important player in the Eagle Ford shale. The company plans to gather, treat and transport gas, oil and condensates and gather and treat flowback and produced water.

For starters, Meritage will own 31 miles of new 16-inch gas gathering lines in Webb County, just north of Laredo, and 12- and 8-inch laterals, with interconnects to systems owned by DCP Midstream, Houston Pipeline Co., Kinder Morgan, Webb Duvall and Enterprise Product Partners.

“We have a vision of significant growth, primarily in the shales,” says Nick Thomas, vice president of business development. “The infrastructure that is and will be required as these shale plays develop will be substantial, and with that there is a lot of focus from both public and private midstream companies.

“Our primary focus has been on grassroots development within the various shale plays—our first project in the Eagle Ford is a grassroots effort and we have another focus area where we soon expect to secure our second grassroots project. We’re working to diversify our exposure to different sets of drilling economics. Our initial project is in the dry-gas window of the Eagle Ford, and we’re looking for exposure to areas driven more by oil or wet-gas economics, whether in the Eagle Ford or other shales.”

Haynesville Midstream

Competing with the Marcellus and the Eagle Ford for the title of “outstanding shale plays” is the Haynesville shale in the ArkLaTex Basin. However, burgeoning production potential could be stymied if midstream builders find it not so easy to keep up.

With a resource potential of some 150 trillion cubic feet of gas (roughly 60% that of Barnett), in addition to an early-stage superior recovery factor and other geological characteristics, the Haynesville has established itself as the most promising shale-gas play among some producers. In fact, some companies’ estimates put current production near 2.4 Bcf per day, which could possibly grow by an extra 25% by year-end as backlogged wells are completed even as new ones coming online.

So, the question is: Can regional pipeline development keep up with production capacity, or is the region prone to a flow bottlenecks that will keep regional gas prices low?

Until now, pipeline capacity has just about kept up with upstream development in the play. Immobile infrastructure, including pipelines and underground storage, which have exorbitant up-front costs and require years to build, already exists in the Haynesville and is evenly dispersed with well-placed interconnects to provide a flowing route for the produced gas through some of the most liquid market hubs (Carthage, Perryville, Henry and Houston Ship Channel hubs) in North America. But the extraordinary growth rate of Haynesville production, if sustained, will require substantial new development of gathering and midstream infrastructure.

However, Haynesville’s location can be somewhat of a disadvantage. Due to its rapid growth and competition from other midstream resources seeking eastern-demand regions like Florida, Southeast U.S., and Mid-Atlantic states, competition from other gas plays can easily stall the migration of this shale’s gas unless additional dedicated intrastate and interstate pipelines are constructed.

Haynesville gas will generally flow in the direction of the Perryville hub and, from there, toward Midwest and eastern U.S. markets. Inherently, there could be three major segments whereby a disruption, due to the lack of pipeline capacity, could interrupt the flow of gas from wellhead to market.

At the outset, the play could lack the necessary gathering systems to collect and process the gas into the respective interstate or intrastate pipelines. Second, a bottleneck could occur due to insufficient interstate or intrastate capacity to flow the gas toward the market hub. Third, gas from other producing regions could displace Haynesville gas and prevent it from reaching the profitable markets.

Also, Haynesville’s fairly high carbon-dioxide-content gas will require treating to achieve pipeline specifications. And because the Haynesville is an over-pressured reservoir with high initial production rates, there is a greater need for treating facilities early the well’s lifecycles.

On the other hand, compression plants are not a necessary until later in the lifecycle, and the gas is dry and relatively low in NGLs compared to other shale plays, so less cryogenic or absorption plants will be needed.

Most gathering contracts in the Haynesville shale are fee-based due to the volumes gathered and treated. Revenue is not directly affected by the wetness of the gas, unlike keep-whole or percent-of-proceeds contracts whereby the gatherer’s proceeds come from the sale of stripped liquids or a percentage of the gas and liquids sold on the market, respectively. Nevertheless, a percentage of all gathering volumes (about 1% to 1.5%) usually are retained as a usage component or due to compressor efficiencies. The sale of any excess retained gas could positively impact the profitability of any gathering project

Recently, the play’s rapid growth has prompted numerous gathering system expansions. Initially, there were two main projects competing for take-away capacity from Haynesville— Enbridge Inc.’s LaCrosse Pipeline and Energy Transfer Partners LP’s (ETP) Tiger Pipeline. But, in July 2010, Enbridge withdrew its pre-application with the Federal Energy Regulatory Commission for its project due to insufficient marketing support.

Meanwhile, Energy Transfer’s 175-mile, 42-inch line looks like a go. The line will start from an interconnect with Houston Pipeline Co. in Panola County, Texas, and move eastward toward the Perryville Hub in Richland Parish, Louisiana. It will have an estimated capacity of 2 Bcf per day, with further expansions possible, and will include connections with seven interstate and one intrastate pipeline for ultimate delivery to Midwest and eastern U.S. markets.

Although, most of its gas will be from the Haynesville shale, some flows will include gas from the traditional East Texas plays, the Fort Worth Basin and the Bossier and Deep Bossier developments. The pipeline is expected to be in service by March 2011. As of August 2010, construction was on schedule to make the start date.

Beyond Perryville, there is considerable pipeline capacity taking gas to the northeastern and mid-western markets, but there is also much competitive gas flowing from regions other than Northeast Texas and Northwest Louisiana. As a result, there will be significant gas-on-gas competition.

Enterprise Products Partners LP is offering a different solution by extending its Acadian gas pipeline northward to pick up Haynesville gas and move it southeastward through Louisiana to access pipelines serving eastern markets and interconnecting with Enterprise’s Acadian system that serves the Mississippi River corridor markets. The new pipeline extension, including 270 miles of 36- to 42-inch pipe with a capacity of 1,800 MMcf per day, could be expanded to 2,100 MMcf per day. To date, Enterprise has executed agreements for nearly the full capacity and plans to start laying pipe in January 2011.

Also, Centerpoint Energy Field Services (CEFS) signed a 15-year agreement with Shell and Encana Corp. in April 2010 to provide gathering services for up to 580 MMcf per day via the Olympia Gathering System, which is expected to be in service by December 2010. Plans include a possible future expansion of 520 MMcf per day.

CEFS signed a similar agreement, in September 2009 to provide gathering services of up to 700 MMcf per day with its Magnolia Gathering System. The system began service in late 2010, and could be expanded to move another 300 MMcf per day in 2011.

Elsewhere, the Regency Logansport gathering system, by Regency Energy Partners LP, was completed in August 2010, and added some 480 MMcf per day of capacity to increase the Regency’s total gathering capacity to 710 MMcf per day.

Tenaska Inc. recently completed its TPF II gathering system, which will move some 1,000 MMcf per day, and Eagle Rock Energy Partners LP plans to expand its ETML gathering system, mainly in the Nacogdoches and San Augustine counties of Texas, to add 300 MMcf per day.

Along with such new-build projects, mergers-and-acquisition activity will likely continue in the gathering and processing sectors as smaller companies sell their assets to the bigger and more established players that can utilize economies of scale to increase revenues because most of the contracts are based on throughput volumes.

Bakken Midstream

Meanwhile, unconventional gas is not the only game in town. Today, when energy folks talk about American oil plays, the Bakken shale in the Williston Basin is invariably the top topic of discussion. It was a hot play a few years ago, and is only getting better. And it has gas, too.

From the production fairway, oil and natural gas operators are pushing the play’s boundaries outward. Continental Resources Inc., Brigham Exploration Co. and EOG Resources Inc. are expanding into western North Dakota. Whiting Petroleum Corp. is pushing into southwestern North Dakota. Others are exploring across the Montana border.

As they and new entrants continue to drill, they are putting the play on the map in a big way. By 2009, North Dakota was #4 when ranking oil-producing states. At the time, the state was flowing some 79.7 million barrels per year. By March 2010, production had increased to more than 277,000 barrels per day or nearly 100 million barrels per year.

According to the North Dakota Industrial Commission, the 112 rigs drilling in the state (at press time) were estimated to produce as much as 450,000 barrels per day in May 2010, which would average 164 million barrels per year. While the total resource base for the Bakken and the Three Forks formations is still being studied, early reports indicate some 200- to 500 billion barrels of oil in place.

As the play grows, moving oil to markets via rail and truck is still underway, but new pipelines are needed, despite the fact that pipeline capacity exceeds oil production in North Dakota. The same is true for gas pipelines. In fact, actual gas volumes at receipt points versus selected pipeline capacities show a variety of utilization.

Enbridge’s Alliance Mainline is nearly full on a continuous basis, although it does have some room to spare. The Oneok’s Viking-TransCanada Emerson is running at half-full. Transcanada’s Great Lakes-TransCanada-Emerson receipt point shows major volatility throughout the latter half of 2009 and into 2010. The Northern Border-TransCanada-Port of Morgan facility has been underutilized since before June 2009.

Still, there continues to be calls for new pipelines. Recently, the governors of North Dakota and Montana called for support of new infrastructure to get oil to market and to encourage more production. Recently, North Dakota Gov. John Hoeven and Montana Gov. Brian Schweitzer met with TransCanada Corp. to discuss a possible “on-ramp” to its Keystone XL Pipeline for area oil producers.

TransCanada is planning an oil pipeline from northern Alberta to refineries in the Gulf Coast and would run close to the border of southwestern North Dakota and through Montana. If built, the line has a targeted service date of 2012.

Hoeven is also encouraging Enbridge to expand its pipeline capacity northward. Enbridge is evaluating its $300-million Enbridge Phase 7 project, via its recent non-binding survey of interest, for an expansion of some 115,000 barrels per day from the Beaver Lodge looping station in northwestern North Dakota, through Stanley, to an existing portal at Berthold.

Elsewhere, Alliance Pipeline recently completed construction of a new interconnect facility near Bantry, North Dakota, to connect to Pecan Pipeline Co.’s 12-inch, 76-mile Prairie Rose Pipeline. The new interconnect provides a much-needed route to bring gas and gas liquids from the Bakken to market. The Alliance system runs through the Williston Basin and transports rich gas, allowing liquids to be extracted at the delivery point rather than near production facilities, thus reducing processing and transportation costs for producers.

“We are bringing EOG’s gas into the Alliance system,” says Tony Straquadine, government affairs manager for Alliance. “We take that into Chicago on our Mainline system.”

EOG Resources Inc. injects gas with up to 1,500-Btu heat content. The rich gas is too high for typical interstate pipelines, but Alliance is a dense-phase, or rich-gas, system that can take the gas to Aux Sable Liquid Products, a world-class fractionation and extraction facility.

“Coming out of North Dakota, that system is like a garden hose coming into a fire hydrant,” he says. Alliance Pipeline operates at 1,900 pounds of pressure, keeping the liquids entrained as gas, and moves 1.6 Bcf per day on average through a 36-inch line—hence the analogy. EOG has firm commitment of 40 MMcf per day on Alliance this year, but it will up that to 80 MMcf in 2011.

“We are custom-made for the North Dakota producers,” Straquadine says. “You could argue that they could put in small processing facilities and process the liquids out near the field, but then how do they move their liquids? We take it whole to Chicago. Beyond the capacity that EOG has committed, we have 108 MMcf per day available to attract incremental associated-gas volumes out of the Bakken.”

The Alliance system was built 10 years ago to serve producers in British Columbia and Alberta to drive the rich gas into the processing facility in Chicago. “Now we have that new entry point in Bantry, North Dakota. Right place, right time,” he says.

In addition to the previously described pipeline, TransCanada has begun construction on its 30-inch, 302-mile, Bison Pipeline that will connect gas production from the Powder River Basin of Wyoming to the Northern Border Pipeline in Morton County, North Dakota. The initial capacity of 477 MMcf per day could be expanded to 1 Bcf, after is starts up in November 2010.

Williston Basin Interstate Pipeline Co. (WBI), the wholly owned gas transmission pipeline subsidiary of MDU Resources Group Inc., plans to expand its existing gas pipeline capacity by 33% in the Bakken in northwestern North Dakota. The expansion will add up to 30 MMcf per day to existing volumes for delivery to Northern Border Pipeline by adding facilities to an existing compressor station in northwestern North Dakota. The targeted in-service date is November 2011.

Along with the pipeline expansion project, WBI is also working with gas producers and processors to add additional natural gas receipt points to its system throughout the Bakken production area. An open season for the Bakken Expansion Project runs through June 2, 2010.

Bridger Pipeline LLC plans to extend its North Dakota oil pipeline transportation system. Shippers will transport oil from an origin near the town of Four Bears, North Dakota, to Belle Fourche Pipeline’s Skunk Hill Junction and to Bridger Pipeline’s Fryburg Station, the origin of Bridger’s Little Missouri Pipeline. The new extension of the system is targeted to be in service during first-quarter 2011, with an initial capacity of 40,000 barrels per day

Enbridge Pipelines (North Dakota) LLC plans to proceed with its previously deferred Phase 6 expansion work west of Beaver Lodge Station in response to recent increases in receipts at its Alexander and Trenton stations, growing production in the area and significant interest expressed by customers. New pumping upgrades will increase capacity of the company’s Alex and Trenton stations, from 93,000 bbl. per day to about 127,000. The work should be completed in 2011.

As mentioned, pipelines are not the only means of take-away transportation from the Bakken. In April, NuStar Energy LP’s St. James, Louisiana, train terminal unloaded its first rail-car shipments of Bakken crude. The company invested $2 million in its St. James facility so it can accept oil by rail in an effort to bring new sources of crude oil to an area that is quickly becoming the nation’s leading crude trading hub.

Through its manifest-rail expansion, NuStar will have the ability to bring in 10,000 bbl. per day of Bakken production.

Meanwhile, U.S. Development Group LLC (USDG) began construction on its new own St. James rail terminal, an oil and condensate train-handling and distribution hub in Louisiana. USDG’s St. James facility is the company’s first crude oil and condensate terminal, and is under development in partnership with Plains All American Pipeline LP.

Served by the Union Pacific Railroad, the St. James rail terminal will be able to handle both manifest and unit-train shipments serving several oil-producing areas in the U.S and Canada in addition to the Bakken. The facility, with an initial capacity of 65,000 bbl. per day, will include several miles of rail track, a fully automated 26-spot rail rack and is expected to be in full operation by year-end 2010.

Beyond take-away, another hot-button topic is the gas processing capacity available for rich Bakken gas. At present, North Dakota has 11 gas processing plants, but more are planned.

Recently, Oneok Partners announced it will invest more than $400 million in new growth projects in the Bakken, including adding 100 MMcf per day of gas processing at its proposed Garden Creek plant in eastern McKenzie County, North Dakota. The facility and related expansions are estimated to cost from $150- to $210 million and will double the partnership's gas processing capacity in the Williston Basin by fourth-quarter 2011.

Elsewhere, in April this year, Hess Corp. filed a letter of intent with the North Dakota Public Service Commission to expand its Tioga gas plant, currently the largest and oldest gas processing plant in the state. The expansion will more than double current throughput with new nameplate capacity of 250 MMcf per day. Hess plans to begin construction in March 2011 and have the $325-million facility operational by December 2012.

Niobrara Midstream

Another unconventional oil play, the venerable Niobrara, is home to several large pipeline systems and more capacity is likely to be built next year as the land rush continues.

The Niobrara oil and gas play is an Upper Cretaceous formation in the Rocky Mountain region. The deep formation underlying northern Colorado, western Nebraska and eastern Wyoming is where the oil rush is taking hold. Highly productive wells are being tapped in Colorado, just south of the Wyoming line. Horizontal drilling and other newer drilling technologies are being applied to the Niobrara formation, which is geologically similar to the North Dakota’s Bakken play.

The self-sourced hydrocarbon system has organic carbon content in the 1% to7% range and is produced at depths of 6,000 to 9,000 feet deep in the Denver-Julesburg (D-J) North Park and Powder River basins. Current focus areas are in and around Wattenburg Field in Weld County, Colorado, and in Laramie, Platte and Goshen counties, Wyoming, around Silo Field. Other areas include the southern portion of the Powder River Basin in Campbell, Converse and Natrona counties and North Park Basin in Jackson, Routt and Moffa counties, Colorado.

Noble Energy (800,000 acres), EOG Resources (400,000 acres), Chesapeake Energy (400,000 acres), East Resources (100,000 acres), Fidelity Exploration and Production (80,000 acres), Petroleum Development (72,000 acres), Voyager Oil & Gas (48,000 acres) and SM Energy (24,000 acres) are some of the major players. Also, Anadarko Petroleum has a large position by way of the Union Pacific Resources Land Grant.

Operators in the area have long produced wet gas and light sweet crude from the D-J Basin. Recent reports suggest the Niobrara could have recoverable resources between 4 billion and 6 billion bbl. of oil equivalent.

Several oil pipelines traverse the Niobrara play, but only one is a major oil system. In Colorado’s D-J Basin, SemGroup Inc.’s much anticipated 526-mile, 12-inch diameter White Cliffs pipeline now provides about 30,000 barrels of oil take-away from the area into the oil hub at Cushing, Oklahoma. A year ago, Noble Energy and Anadarko were enthusiastic about hooking up to the system. Both operators have subscribed to 10,000 barrels daily.

“There have been times when we had to shut in wells up to a week at a time because the area lacked sufficient refining capacity,” said Anadarko’s facilities engineer Joe Aucoin, from his office at the White Cliffs’ connect near Plattesville. “It’s huge for us.”

At the time, price realizations in the field were expected to improve by as much as $6 per bbl., thanks to cost efficiencies from the new pipeline, according to Anadarko. Field-wide, savings are a potential $65 million per year at the pipeline’s capacity, according to Wood Mackenzie.

White Cliffs will not only provide producers such as Anadarko and Noble Energy with access to more markets and potentially higher prices for their crude, but also nearby oil-polishing facilities see reduced costs that were previously incurred in hot-oiling processes at the individual lease sites. Other benefits of the pipeline include reduced air emissions from truck traffic, which used to be the transportation mode for take-away from the play, and an onsite centralized truck facility.

The common carrier originates in Platteville, Colorado, northeast of Denver, and terminates at SemCrude’s storage facility in Cushing. It has 100,000 bbl. of crude oil storage in Platteville, adjacent to SemCrude’s 10-bay truck-unloading facility with 20,000 bbl. of crude oil storage. White Cliffs is the only line connecting the D-J Basin directly to Cushing. Despite its single-pump stations design, the pipeline is expandable to 50,000 bbl. per day. The pipeline is a major asset for SemGroup, the company that recently emerged from reorganization brought about by its 2009 Chapter 11 bankruptcy.

Operators were also anticipating significant increased take-away capacity for NGLs. The D-J Basin Lateral Pipeline, which began operations in March 2009, is a 125-mile NGL line connecting the D-J Basin with the Overland Pass Pipeline. (The 760-mile Overland line can transport 110,000 bbl. of NGLs per day. It runs from Opal, Wyoming, to Conway, Kansas.)

The D-J Basin Lateral’s capacity is 55,000 bbl. per day from existing gas processing facilities in the D-J Basin, including DCP Midstream’s Lucerne and Mewborne plants. Also, DCP’s Platteville and Greeley facilities are connected to Mewborne. Increasing NGL production in the Rocky Mountain region correlates with increasing gas development.

“With the Overland and D-J Lateral in place, take-away constraints are lifting for producers,” said Roz Elliot, director of public affairs for DCP Midstream. Previously, the field’s NGLs had to travel on the Phillips Petroleum line down to Borger, Texas, or be trucked to alternative markets in Kansas. The Wattenberg area’s intense land use—whether urban or agricultural—and air, water, noise and other regulations dictate that environmental best practices be a constant focus for operators.