?A plethora of much-needed gas-pipeline projects are on drafting boards, driven by increasing U.S. onshore production. But some projects are stymied by commercial lenders’ frozen funds and the precipitous fall in equity markets, making funding difficult. Midstream master limited partnerships (MLPs) and private-equity investment firms may get the job done.

This year, by October, about 2,713 miles of new or expansion gas-pipeline projects had been completed onshore the U.S. In comparison, some 1,700 miles of onshore gas pipe was installed in 2007—more than in any year since 2003—according to Energy Information Agency (EIA) data.

“There has been an unprecedented amount of domestic spending on pipeline infrastructure over the last couple of years, by a factor of six,” says Mike Parham, managing director of Costa Mesa, California-based McGladrey Capital LLC, an investment-banking firm.

“The real pipeline growth areas seem to be in Alaska, the Midcontinent and the Rockies,” he says. “But I don’t want to underestimate even West Texas, New Mexico and some of the Permian Basin. Across the board, the industry spent about $12 billion nationwide this year, compared with about $6 billion last year. And only about $2 billion in 2006.”

How will new projects be funded? “That’s the big question. I think the MLPs are a likely source,” says Parham. “They have to put their money into projects like these and I think they will also raise more capital, although the markets aren’t being very friendly right now. Also, in this market, mezzanine funding is going to play a big role.”

In fact, due to the rattled global financial system, Parham sees institutional money making a flight to safety, as well as private-equity capital that historically wouldn’t touch energy, and hedge funds, all turning to energy and infrastructure-related investments.

Also, pension funds are directly investing in infrastructure for long-term income. “In the past, the cyclicality of the industry spooked a lot of these types of investors,” says Parham. “But now, it is the rest of the market that is spooking them.

“They are seeing that the long-term trend for infrastructure is quite positive. We have an archaic grid and a tremendous need for pipelines. We need an extreme makeover. I can’t find another industry where a dollar should be invested, other than in energy.”

Several trends have developed in the U.S. gas marketplace to promote escalation of new-build pipeline projects: the maturity of conventional gas resources, such as the Gulf of Mexico; increasing output from unconventional gas plays, including Texas, Oklahoma, Arkansas and Louisiana shales, and East Texas and Rockies tight gas; and increasing demand for gas from the power sector.

Pipelines are not currently where they need to be.

While some trends encourage pipeline growth, others discourage it, creating a tug-of-war between increasing demand for new infrastructure and decreasing supply of capital and enough production to support them.

Some 2,600 miles of planned new gas pipe has instead been cancelled. One project was a new, 1,600-mile, $2-billion joint venture between Centerpoint Energy Inc. of Houston and Duke Energy Corp.of Charlotte, North Carolina. Meant to be an interstate expansion line, it would have run from Dumas, Texas, to southwestern Pennsylvania. It was cancelled “due to lack of market support,” according to the EIA.

Also cancelled, “for lack of customer interest,” was Duke’s Alliance Lebanon Connector, a new 170-mile pipe from Cook County, Illinois, to Indiana, which would have used the existing Texas Eastern Lebanon Lateral to transport supply to Northeastern U.S. markets.

Houston-based El Paso Corp. cancelled its Continental Connector, a 650-mile line that was planned to extend from the vicinity of Custer, Oklahoma, to Perryville, Louisiana, “due to competition in the marketplace.”

According to a recent analysis by Houston-based Tudor, Pickering, Holt & Co. Securities, if public-debt and project-finance markets remain closed, other major infrastructure projects are at risk. Ironically, past forecasts indicated that 2008 would be the heavy capex-spend year for most of the infrastructure companies. The trend was expected to slow in 2009, and ramp up again in 2010.

Meanwhile, E&Ps find themselves paring drilling plans to operate within cash flow—a reversal of the previous standard of spending up to three times cash flow on drilling—due to nearly shuttered debt and equity markets. Reduced drilling will reduce demand for new take-away capacity.

Pritchard Capital Partners analysts report, “The financial crisis and lower commodity prices are driving a cutback in the gas-rig count in the U.S. as private and public E&Ps are forced to curb capex and activity levels. Many E&P companies are now talking about drilling within cash flow in 2009.”

Private capital

Despite this, there are still quite a few pipeline projects planned. But who will fund them? “It will continue to be pipeline MLPs,” says Jeff Rawls. Rawls is a managing director for the $1.4-billion private-equity fund NGP Midstream and Resources, based in Dallas and an affiliate of NGP Energy Capital Management.

“Midstream MLPs have nearly doubled in number over the past five years,” he says. “There were roughly 40 in 2004. Today, we see roughly 80. What I think is more interesting than the doubling of the number is the market capitalization.”

In fewer than five years, MLP market capitalization has grown from $40 billion to $140 billion. “And we see this trend continuing. But the big challenge will be access to capital to effectuate that growth.”

In fourth-quarter 2008 global financial markets, funding MLPs is “not for a weak stomach,” he says. “Most projects have to commit capital well in advance of getting regulatory approval and rights of way. And major pipeline development usually means a two- to three-year period without positive cash flow.”

Another infrastructure-funding source comes from a traditionally upstream-focused private-equity investment firm, Houston- and Dallas-based EnCap Investments LP. Complementary to EnCap’s E&P investment portfolio and to provide haven to investors seeking quality, EnCap is starting a new investment fund.

“We historically have primarily been focused on the upstream sector of the business, and as a result, have only done a handful of midstream deals. While they’ve all been successful, we recently decided we needed to re-position ourselves in order to capture more opportunities in that sector,” says David Miller, EnCap partner and co-founder.

“The U.S. is going to use more and more natural gas, and an increasing percentage of future supply will come from the various unconventional gas plays. While there might be a lull in activity for awhile, over the intermediate term and certainly the long haul, we think drilling in the resource plays is going to be very robust.

“Every time you drill a gas well, a gathering system has to be put in place, and much of that gas has to be treated and processed. So, there are going to be substantial infrastructure needs in order to get the new gas to market, and along with that we believe there are going to be a lot of compelling investment opportunities in the midstream area,” he says.

The repositioning Miller references which started with EnCap entering into a partnership with Flatrock Energy, a San Antonio-based company with deep midstream experience and contacts, now has taken the form of a new institutional fund. The marketing for EnCap Energy Infrastructure Fund was launched four to five months ago, and the first closing is expected to occur in December, followed by a second closing early next year. EnCap and Flatrock will be co-general partners (70% EnCap/30% Flatrock).

Going forward, EnCap will continue investing its existing $2.5-billion fund focused on the upstream sector and at the same time, will administer its Infrastructure Fund for midstream investments, including pipelines, gathering systems, processing plants, compression and storage. “Most of the investors in the new midstream fund are expected to come from EnCap’s existing base of institutional LPs,” says Miller.

“The Flatrock team brings three decades of commercial and advisory experience in the midstream area to the table, as well as a wealth of contacts, and we bring our track record as oil and gas private equity investors and our relationships within the institutional community.

“EnCap and several other private equity funds have been a force providing growth capital to the upstream sector of the business, and our objective with the creation of this new fund and our partnership with Flatrock is to become a similar force in the midstream space.”

Rockies to Ohio

Meanwhile, many gas-pipeline projects are still going ahead, in anticipation of more stable markets. Taking into account currently proposed expansion projects, the level of pipeline construction activity in the U.S. should increase substantially between 2008 and 2010. As many projects compete for the same markets, not all will come to fruition.

Still, about 200 projects, representing a potential 10,100 miles of new large pipe and daily capacity of some 103 billion cubic feet (Bcf) of gas, are planned or have been approved by U.S. regulatory authorities, according to the EIA. If all are completed, about 2% more pipeline miles would be added to the national grid and overall network capacity would increase more than 38%. Current estimates for the cost of this effort are nearly $28 billion.

Earlier this year, the second stage of the Rockies Express system, from eastern Colorado to eastern Missouri, was placed into full service, adding some 750 million cubic feet of daily capacity.

The $4.9-billion Rockies Express Pipeline (Rex) is a mostly constructed, 1,679-mile, 42-inch-diameter line that will take Rockies producers’ gas east. The high-pressure line (1,480 psi) originates in Rio Blanco County, Colorado, and will terminate in Clarington, Ohio, transporting up to 1.8 Bcf per day. The developer, Rockies Express Pipeline LLC, is a joint venture of Kinder Morgan Energy Partners LP (which will be operator upon completion), Sempra Pipelines & Storage and ConocoPhillips.

It is in three parts: Rex Entrega, a 328-mile section extending from Rio Blanco to Weld County, Colorado; Rex West, a 713-mile line to Audrain County, Missouri; and Rex East, a 638-mile line to Monroe County, Ohio. The lattermost is under construction.

“Rex West was recently put in service and we are working on Rex East now,” says Doug Walker, president of Rockies Express Pipeline LLC.

The new capacity is already affecting price differentials. From January through April, the average price in Rockies trading locations was within 90 cents of the Henry Hub average price, compared with discounts exceeding $1.40 during early 2007.

“During 2008, Rex East efforts were focused on initially building to Lebanon rather than all the way to Clarington, in part due to some FERC (Federal Energy Regulatory Commission) conditions east of Lebanon,” says Walker. “Altogether, Rex East to Lebanon will be built in eight spreads, a distance of about 444 miles, and will employ five different pipeline contractors.” Construction was simultaneously under way on all of the spreads at press time.

“On Rex East, there have been a few delays due to the impact from rain that left water on the rights of way,” says Walker. Hurricane Ike, flooding of the Mississippi River earlier in the year and severe weather in Indiana and Illinois in the spring all caused delays. “We’ve had more than our share of weather issues,” says Walker. “We assess the situation each morning, and we get the crews out when we can.”

The intent is to provide service to points east by early 2009. “At the end of October, we announced that initial service on Rex East will be April 1,” says Walker. That will provide Rex shippers access to points in Illinois and Indiana, up to and including the Putnam County, Indiana, interconnect with Panhandle Eastern Pipeline.

“We are planning to bring the project into initial service in April to benefit our shippers who desire to move their gas as far east as possible, by establishing service to downstream pipelines that serve the Midwest and Northeast markets,” Walker says.

“We can convey the Rocky Mountain producers’ gas another step closer to constrained and high-value markets by establishing new deliveries into Illinois and Indiana, and then ultimately into Ohio. We’ve already unlocked their ability to get their gas out of the Rockies (via Rex West), which has traditionally been a constrained area due to more production capability than could get to market.”

Meanwhile, the targeted service date to Lebanon is June 15, 2009; the line should arrive in Clarington, Ohio—representing full build-out—by November 1, 2009.

To hit those dates, construction during this winter will be necessary. Although the weather could cause further delay, the pipe, compressors and other materials have been ordered (at favorable pre-2006 prices) and have been delivered or are on their way.

“Our steel price and overall cost for pipe had been established for quite some time, so we avoided a lot of that run-up (of 2007 and 2008) when we made the purchases. If we were to start to build this project today, it would be hard to re-create it with current pricing,” he says.

As soon as final regulatory approvals are secured, the next leg of construction will involve horizontal drilling under the Big Darby and Little Miami rivers in Ohio, in preparation of pipeline installation. Because the rivers are nationally designated “wild and scenic,” several government agencies have jurisdiction. While more expensive than other river-crossing methods, horizontal drilling is the most non-invasive choice.

“We’ve worked with the Ohio Power Siting Board (an agency that reviews and approves new energy facilities like pipelines) and have reached an agreement with them,” says Walker. “Certainly we don’t want to do anything to damage those rivers, so we needed to convince them that there is an effective way to cross a river like that. It’s always good to get those approvals done ahead of time.”

The developer will also use horizontal drilling under “cultural resource sites” where arrowheads or other artifacts may be present.
After Rex East is completed, what’s next?

“We think there will be more pipelines built out from the Rockies. We are actively pursuing a Chicago-destined project. I think it is clear to say that, in the not-too-distant future, there will be other pipelines, as the area continues to be prolific,” says Walker.

To Oregon, New York

Next up on the drawing board, heading west from the Rockies to California, is the $3-billion Ruby Pipeline. Houston-based El Paso Corp.’s Ruby Pipeline LLC has already received commitments of more than 1.1 Bcf per day in 10- to 15-year contracts from Rockies gas shippers. In October, anchor shipper PG&E Corp.’s Pacific Gas and Electric Co. received a favorable proposed decision from the California Public Utilities Commission on its plan to obtain capacity of 375,000 dekatherms per day.

Ruby Pipeline is slated to handle some 1.5 Bcf of daily capacity. That includes 670 miles of 42-inch-diameter pipe that will extend from the Opal Hub in Wyoming to interconnects in Malin, Oregon, near California. El Paso plans to file a certificate application with FERC in January 2009.

The company has already signed purchase contracts with two steel mills and executed incentive-based contracts with three construction companies to manage costs. El Paso will finance Ruby from free cash flow, project financing and other capital but does not plan to issue equity, although it may bring in equity partners. March 2011 is the target completion date.

Building on the end capacity of Rex will be the Northeast Express Pipeline, a joint venture by Kinder Morgan Energy Partners LP and Sempra Energy.

The first part of Northeast Express originates at Rex in Lebanon, Ohio, with an expansion to Clarington. “Being able to take that gas gives shippers the option of extending their path and reaching new markets,” says John Eagleton, vice president of business development for Kinder Morgan. “Another possibility is to connect to the ANR Pipeline, which has about 500 million a day of unused capacity.”

By adding horsepower upstream of Clarington on Rex, Kinder Morgan can cost-effectively achieve the expansion of Rex, says Eagleton.

“From a commercial standpoint, the Northeast Express will take lease capacity on the Rockies Express and incorporate that into our rate design,” he says. The greenfield build will start at Clarington and run east through Steckman Ridge in Pennsylvania and go up to Princeton Junction, New Jersey, about 350 miles, with a 42-inch-diameter pipeline. It will have an initial capacity of 1.5 Bcf per day.

The next phase will be construction of a 30-inch-diameter line up to Linden, about 32 miles. Beyond that, Kinder Morgan is in discussions with some of the New York local distribution companies about extending further into their markets. Shippers on the pipeline would be able to contract from Lebanon or Clarington.

“We are also looking at building a 29-mile, 30-inch-diameter line from Linden to Hoboken, New Jersey. Interestingly, it involves the installation of 30,000 horsepower at Princeton, which could take advantage of the fact that there is a decreasing pressure gradient from Princeton into the delivery points.”

Shale plays

Douglas A. Sipe, FERC outreach manager, division of gas, environment and engineering, sees a burgeoning market for new pipeline construction in shale plays. “We evaluate plays just like everyone else. We are very bullish relative to continuing investments in the Barnett, Haynesville and Marcellus areas.”

Also, analysts such as at research and consulting firm Wood Mackenzie and at MLP-structured midstream operator Boardwalk Pipeline Partners expect massive increases in shale-gas production. According to their data, Barnett shale production is expected to grow by another 3.9 Bcf by 2015; East Texas/Bossier sands by 1.1 billion by 2015; Haynesville shale by 4.1 billion by 2014; Caney/Woodford by 1.6 billion by 2015; and Fayetteville by 2.9 billion by 2015. Although not yet quantified, new production will also come from Petrohawk Energy Corp.’s newly discovered Eagle Ford shale play in South Texas.

Even there, substantial challenges loom for new pipeline projects.

“I think gas producers are going to have to continue to support and push the major infrastructure projects,” says Sipe. “But developers have two major concerns: huge labor costs and the fact that some contractors cannot present AAA credit to back up their projects.

“Also, some mills are requiring initial deposits, which would be in advance of FERC approval and rights-of-way acquisition, so pipeline companies must risk early capital.”

Nonetheless, production increases, particularly in the Barnett and Fayetteville plays, have created greater demand for take-away capacity and more pipeline interconnections.

In the Fayetteville, Kinder Morgan has joined with Dallas-based Energy Transfer Partners LP (ETP) in a 50/50 joint venture, Fayetteville Express Pipeline LLC (FEP). The venture plans to develop a 187-mile line from Conway County, Arkansas, eastward through White County, Arkansas, terminating at an interconnect with Trunkline Gas Co. in Quitman County, Mississippi. It will have an initial capacity of 2 Bcf per day. Pending regulatory approvals, the $1.3-billion line is expected to be in service by late 2010 or early 2011.

EP has already secured binding 10-year commitments totaling 1.575-million dekatherms per day for gas carried on Fayetteville Express. Southwestern Energy Services, a subsidiary of Houston-based Southwestern Energy Co., anted up for 1.2 million. Chesapeake Energy Marketing Inc., an affiliate of Chesapeake Energy Corp., has signed up for 375,000, with an option for an additional 125,000.

Boardwalk, based in Houston, plans a $5-billion line in Arkansas called the Fayetteville Lateral, beginning in Conway County and extending 167 miles through eight counties as it heads east to Lula, Mississippi. The 36-inch-diameter pipe will move Fayetteville gas to northeastern, southeastern and upper Midwestern markets, including transmission lines in Oklahoma and Texas.

“Boardwalk has about 1,000 miles of large-diameter pipe that we have been working on for the last two years,” says Brian Cody, senior vice president and chief commercial officer for Boardwalk. “When we began these projects a little over a year ago, we had about 3 Bcf signed up. A big part of that is getting the shale gas out of these regions and moving it into more lucrative markets.”

Super-pipe

One of the largest existing gas pipelines, Tulsa, Oklahoma-based William Cos.’ Transco line, may also undergo expansion. Transco is a 10,500-mile system that transports gas to markets from Texas to New York.

“We are working on two projects,” says Jim Moore, director of business development for Williams Gas Pipeline-Transco. “Our Station 85 (near Butler, Alabama) North expansion is a 380-million-cubic-foot-per-day expansion into North Carolina to serve power-generation loads along that route. We have contracts for that, and will phase it into service in 2010 and 2011.”

The company also plans an expansion of its Mobile Bay line. It runs from Station 85 South toward Mobile, Alabama, with interconnects with Florida Gas Transmission’s Gulfstream. “It will take advantage of large amounts of gas from the Barnett shale area. When we put those projects into service, our capacity from Station 85 will be more than 5 Bcf per day.

“With Marcellus gas supply growing, that provides additional supply options in southern or northern Pennsylvania or even southern New York. Supply could be connected to our Leidy, Pennsylvania, line.”

Elsewhere, DCP Midstream Partners LP of Denver and M2 Midstream LLC of Houston have signed on to pursue development of a new large-diameter line to move gas from the Haynesville shale play in northwestern Louisiana.

As an extension of DCP’s Pelico Intrastate Pipeline, the new pipe, named the Haynesville Connector, would originate in western DeSoto Parish and extend more than 150 miles to Delhi, Louisiana, providing access to take-away pipe in the Delhi area. The Haynesville Connector is expected to be online near the end of 2009 and would move some 1.5 Bcf of gas per day by early 2010.

Getting it right

While Barnett shale pipeline projects have helped producers get their gas to market, the multiple, uncoordinated gathering systems may not have been the best way to go, and should not be copied in Appalachia’s Marcellus shale play.

“The Fort Worth Barnett shale is an excellent example of how not to do it,” says Rodney Waller, senior vice president and chief governance officer for Range Resources Corp., based in Fort Worth, Texas.
Range Resources is a leading acreage-holder in the Marcellus play and a leading producer in the Barnett play.

“Because the (Fort Worth Basin) midstream companies could not respond quickly enough to XTO, Quicksilver and Chesapeake, those companies had to build their own systems,” says Waller. “As more and more gas was delivered into that conglomeration of spaghetti, although it is all interconnected, it all has different pressures and different flows. It doesn’t work.

“In the Marcellus, if we build a unified system, we can actually build 50% less infrastructure with lower costs and better deliverabilities with economies of scale.”

Waller suggests coordinating pipeline build-outs among producers, pipeline developers, gas aggregators and gas processors such as Denver-based MarkWest Energy Partners LP.

“The way I see it, we have a four-legged stool,” says Waller. “Range is the developer of the reserves. MarkWest, with its processing and gathering, is the second leg. The third leg is the group of gathering- and transmission-line developers. They need to understand the urgency and the cost structure needed to move this quickly within the next two to three years. If we have a unified system throughout the Marcellus, that can give a very short term for the entire development in the area.

“The fourth leg of the stool, as we move this gas—as much as 400 million cubic feet a day over the next three to five years—is going to have to be gas aggregators that can help us move this gas on an economical basis right here in the demand area.”

Randy Nickerson, senior vice president and chief commercial officer with MarkWest, agrees.

“Every single shale play has been plagued with small infrastructure challenges,” he says. “In the Haynesville and Marcellus, there are going to be gathering opportunities. Those are code words for ‘you better get it right or your gas is going to stay in the well after you drill it.’ So we take that very seriously.”

In the Woodford, MarkWest has built some 400 miles of mostly 16-inch gathering systems and 25 compressor stations. “Our view is that, if producers are willing to invest the money, take the risk and believe in the play, then our role is to come in next to them to make sure they have the infrastructure. As we have learned in these shale plays, when the producer gets it right, and once the gas comes, you just can’t catch up,” he says.

MarkWest is expanding its Cobb gas-processing plant in West Virginia to 70 million cubic feet of daily capacity and to more than?200 million per day by mid-2010. The company will also build a gas-gathering and -processing system in Majorsville, West Virginia. Meanwhile, MarkWest and Range Resources will build the first large gas-processing plant in Pennsylvania’s section of the Marcellus.

At times, three legs work fine, such as for Dominion Transmission Inc., a subsidiary of Richmond, Virginia-based Dominion Resources Inc. and owner of 42,000 miles of gas pipe, 1.1 trillion cubic feet equivalent of gas and oil reserves, and power-generation and -transmission facilities, combining gas production and pipeline development into one company.

“We are not just a pipeline operator, but also an E&P company,” says Donald Raikes, vice president of marketing and customer service. “We are right in the middle of the Marcellus play.”

Dominion owns or leases 1.9 million acres prospective for the Appalachian Basin’s Huron and Marcellus shale gas, and its Dominion Hub I project will build take-away capacity from Rex’s termination at Clarington, Ohio.

The hub is “producer-based and producer-pushed,” says Raikes. “It’s an interconnect to Delmont, Pennsylvania. We also have the Dominion Hub II project, which is a Leidy-to-Albany system. It’s a small project, but the Albany area needed some growth.”

The company also plans Dominion Hub III, a new firm-receipt point realignment that is to provide existing shippers access to Rockies gas. Dominion also plans to build the Appalachian Gateway project to provide new extraction and gathering facilities, taking gas to Oakford, Pennsylvania.

“This project is part of the renaissance in Appalachia. We saw, even before Marcellus mania, the tremendous growth in drilling here. We were getting to the point at which we would have to curtail some production from coming on our system. This hub project, which includes gathering and extraction, will be another billion-dollar investment for Dominion in the Appalachian Basin.”

Canadian pipe

Farther north is one of the largest proposals to move gas into U.S. markets—TransCanada Corp.’s Alaskan Gas Pipeline. The Calgary-based company already has some 36,600 miles of wholly owned pipe.

On deck is a $25.1-billion plan for a line from Prudhoe Bay, Alaska, to the Yukon border ($10.9 billion), and then to Boundary Lake in Alberta ($9.2 billion), and a Prudhoe Bay gas-treatment plant ($5.8 billion).

“This pipeline is probably the biggest binary decision, in terms of gas supply, that could happen to the North American gas market,” says Dennis McConaghy, executive vice president, pipeline strategy and development.

“If it comes online, it will be at least 4.5 Bcf a day. There are very few projects that, when they come on, have this kind of one-time impact.

“The Alaska gas resource is about 17% of known U.S. gas reserves. That makes accessing this resource a very significant prize.”

McConaghy sees a U.S. market evolving over the next 10 to 15 years that may exceed 70 Bcf per day.

“(Alaska) Governor (Sarah) Palin signed the bill that puts us on track to receive the license for this two days before she was named the vice presidential candidate. Having the license means we have a contractual obligation to hold an open season and pursue a FERC certification,” says McConaghy.

“One of the key provisions of this open season will be rolled-in tolls, which is different from the policy of the Lower 48. The Alaskan policy is derived from the state’s concerns about open access and basin development.”

McConaghy notes that the pipeline is still 10 years from being in service, even if Trans­Canada has a successful round of commercial negotiations that would assure confidence in the open season’s success.

Meanwhile, competing with the Trans­Canada line is the 700-mile Denali, a joint venture of ConocoPhillips and BP Plc. If built, the project would move some 4 Bcf of gas per day into North American markets. If it has a successful open season, the partners intend to obtain FERC and Canadian National Energy Board certifications to start construction.

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