Midstream companies are racing to come up with ways to carry vast supplies of U.S. crude oil to market.

In mid-May, constant construction kicked up dust at Kinder Morgan’s terminals along the Houston Ship Channel east of the city. High above the activity on the ground, workers made their way along the tops of a dozen or more new, multimillion-dollar storage tanks. Oversized construction cranes stretched skyward. Scaffolding held new pipe next to dirt roads.

One of the planned facilities—at press time just being scratched out in a sandy field—will connect to the Kinder Morgan Crude & Condensate (KMCC) pipeline after a piece is built hundreds of feet under the channel.

The pipeline ends at what is commonly referred to as the spaghetti bowl: the tangle of pipelines snaking and bending through Kinder Morgan’s terminals at the Ship Channel. Here, the 300,000-barrel-per-day KMCC line ends, in the Texas cities of Galena Park and Pasadena. Combined, the terminals have more than 26 million barrels of storage capacity.

Whether the workers realize it or not, the KMCC pipeline is part of the metamorphosis under way in the oil and gas industry. Surging U.S. shale crude production has so overpowered existing infrastructure that it is now transforming it—from the products lines carry, to the direction they flow.

The need for infrastructure is born of two factors. Successful shale plays have been oil scavenger hunts, with finds in sometimes remote and unexpected areas. First to be discovered were natural gas shale plays; then technology was applied to develop liquids plays and revive conventional oil-producing areas. Often, infrastructure in these plays was simply nonexistent or inadequate.

Second, the nation’s existing midstream infrastructure doesn’t match today’s markets. For 40 years, U.S. energy policy assumed domestic production would grow scarcer and imports more critical, said Frank A. Verrastro, senior vice president and James R. Schlesinger Chair for Energy & Geopolitics at the Center for Strategic & International Studies, speaking at IHS CERAWeek 2013 in Houston. Instead, just the opposite has happened.

Ironically, as midstream infrastructure builds out in these production areas, moving crude by rail has become a popular option. Although it is more expensive, rail doesn’t require the longterm capacity commitment that producers must make for pipeline capacity, commitments that could backfire, notes Sandy Fielden, director of energy analytics at RBN Energy, Houston. And it offers flexible destination options.

For the past several years, as shale development moved into high gear, oil was shipped from the oil fields in the Permian Basin, Eagle Ford or Bakken shale plays via rail, barge or columns of trucks. But midstream companies like Kinder Morgan Inc., NuStar Energy LP, Magellan Midstream Partners LP and others are increasingly moving to reconfigure, reactivate or redirect existing pipelines to meet changing market dynamics. Often, they are clearing the way for crude oil moves by retooling pipes used in the past for petroleum products or natural gas that are below capacity—or simply redundant. That repurposing of existing systems comes along with reversals, switching the direction of pipelines’ flow.

In the Northeast, for instance, the huge Marcellus shale play is removing the need for natural gas shipments into the region from the Rockies, Canada and the Gulf Coast. As a result, many gas pipeline company revenue models “are being seriously impacted by reduced flows of natural gas,” says Fielden.

Some of the plans are audacious: A proposal offered by Kinder Morgan is its Freedom pipeline project, a gas-to-oil conversion that would send oil from Midland, Texas, to California, at a cost of $2 billion. (At press time, KMI shelved this project, as it did not receive enough interest from oil producers.)

In another instance, Calgary’s TransCanada Corp. is contemplating a project that could rewrite the way oil is imported into the U.S. Whether these proposals happen, or get moved aside by competing projects, remains to be seen.

The money involved in this midstream revolution is every bit as grand as the projects contemplated. If producers are keen-enough to sign deals, Kinder Morgan alone will spend nearly $2.5 billion on pipeline change-ups. The company has already invested $220 million to convert its KMCC pipeline, completed in 2012, from service as a natural gas line out of the Eagle Ford shale play in South Texas into one moving liquids from that play to the Houston Ship Channel.

“We were able to move (natural gas) load over onto some of the other lines so we could free up that line for crude and condensate,” says Don Lindley, Kinder Morgan Energy Partners’ president of natural gas liquids business development. “From the time that we signed the deal with Petrohawk [Energy Corp.] until we were in service was in the neighborhood of 14 months.” By contrast, a new pipeline might take two years or more to build.

As the centers of production in the U.S. shifted over the past five years, oil flow was upended from its traditional south-to-north flow. Crude volumes sent from the Gulf Coast to the Midwest fell by 37%. Flows to the south increased 56%. Factoring in petroleum products and oil, the push of resources from the Midwest to the Gulf Coast increased 128% in those four years. Verrastro estimates that by 2014, major Midcontinent plays will enjoy an additional 1.4 million barrels per day of projected pipeline capacity from the Cushing, Oklahoma, trading hub—delivery point for New York Mercantile Exchange West Texas Intermediate futures contracts—to the Gulf Coast.

And more oil is coming. In 2011, U.S. production was 5.65 million barrels per day. By 2012, it had climbed by 790,000 barrels per day—the largest annual change since commercial crude oil production began in 1859, according to the U.S. Energy Information Administration (EIA). By fourth-quarter 2014, production is forecast to rise to 8.17 million barrels per day from first-quarter 2013 production of 7.42 million barrels.

As the oil amasses, producers need more outlets, and midstream companies are eyeing opportunities, even for dead pipe.

Idle lines revived

The tiny Texas town of Pettus consists of roughly 550 people, a Dairy Queen, and a nexus of pipelines. It’s never been much more than a crossroads in South Texas. And after a brief oil boom in the 1930s, the town was dormant. Then, a few years ago, the Eagle Ford shale upped the ante.

Increases in Eagle Ford oil and gas production have created an urgent demand for pipelines out of the play. Companies such as NuStar Energy LP, headquartered in San Antonio, are meeting the challenge by making rapidfire changes, says Curt Anastasio, president and chief executive officer. NuStar was spun out of refining giant Valero Energy Corp. in 2007.

NuStar’s approach has been to repurpose what’s in the ground. A 60-mile line from Pettus to Corpus Christi, Texas, had been empty since November 2005. By 2011, amid roaring Eagle Ford production, NuStar brought it back to life.

“There was an opportunity to reactivate an asset that was no longer in use, and hadn’t been in several years, because of the Eagle Ford production,” Anastasio says. The pipe ties in with Koch Pipeline Co.’s infrastructure, adding 30,000 barrels a day of capacity.

“We’ve been able to get up very quickly to 100,000 barrels a day so far, because we had pipe in the ground, underutilized assets,” he says. “We just had to invest to change the direction of their flow. That’s why we were the first company to move Eagle Ford crude.”

Other companies have had to build new assets. Several billion dollars’ worth of energy pipeline projects are under development in the Eagle Ford. And in Texas, more than 90,000 miles of pipeline and gathering lines were built in the past three years.

While not all companies have idle pipelines to put to use, they see similar opportunities in pipelines dedicated to gas and petroleum that have fallen on the half-empty side.

Faced with declining throughput on one of its lines, NuStar reversed the flow of a pipeline running from Corpus Christi to Three Rivers, Texas, and converted it from refined products to crude. The change in direction turns the fundamentals of pipeline flow on its head.

“As you can imagine, a lot of these U.S. pipeline systems used to move imported crude oil and feedstocks from the U.S. Gulf north to the big trunk pipelines and the refineries,” Anastasio says. “And now of course it’s the opposite. With all of the domestic production and the Canadian production, for the most part people want to move north to south. That’s what these reversals are about.”

NuStar has continued to revamp its portfolio of underused lines, with plans to construct a pipeline connection to its existing 12-inch Pettus line and other facilities.

Market space

Growing supplies of light crude in the Midcontinent have altered the mindset of midstream and downstream operators, but basic transportation is lacking. “Crude oil production is really growing in areas that have little, or in some cases, like the Bakken, no pipeline infrastructure,” says Mark L. Reichman, an analyst for Simmons & Co. International, Houston. “Basically, what you’re doing is providing an outlet for those producers, so they can transport their volumes to the best markets for their crude.”

On any given night five years ago, peering down at North Dakota from space would have revealed another dark spot on the planet’s surface. Now, in the northern darkness the light bloom of industrial activity and natural gas flaring is bright enough to rival large cities. North Dakota oil producers must flare approximately 30% of produced gas due to a lack of infrastructure.

Such robust activity comes with both rewards and frustration. Producers in plays across the country are facing the possibility of stranded product. In North Dakota, where pipeline capacity is negligible for now, operators have turned primarily to more costly rail to move crude out. “If the supply is stranded, it can’t get to market and it’s going to sell at a big discount,” Reichman says.

The oil flow in and out of Canada is also being studied for pipeline reversals and conversions. TransCanada is conducting an open season to gauge shipper interest in converting a transcontinental natural gas line to crude oil use. The Energy East Pipeline project would convert capacity in approximately 1,864 miles of TransCanada’s existing Canadian Mainline to crude oil service. The company would construct up to 869 miles of new pipeline as well.

“It is all about market demand,” says Philippe Cannon, a spokesman for TransCanada. “We have been discussing this initiative with shippers and refiners for months now to gauge their interest. We believe there is strong interest and that is why we moved to an open season to negotiate firm, binding commitments.”

The multibillion-dollar project has the potential to transport as much as 850,000 barrels per day to Eastern Canada. If the open season is successful, TransCanada intends to proceed with the necessary regulatory applications for approvals to construct and operate the required facilities, with a potential in-service date in late 2017.

The project would enhance Canadian producers’ access to markets and reduce reliance on crude oil imports from overseas. Eastern Canada currently imports more than 600,000 barrels a day—80% of its refinery feedstock— from Saudi Arabia, Nigeria, Venezuela, Algeria and other countries. The pipeline would also help address price volatility known as the “bitumen bubble” by ensuring Canadian oil gets a better price by competing directly with more expensive imported crude trading on the world market. Heavy bitumen produced from Western Canada’s oil sands is costly to produce but, thanks in part to the lack of midstream infrastructure, sells at a significant discount.

Many more pipeline projects are in progress or have been built, most of them transforming natural gas pipelines falling short of capacity. The Federal Energy Regulatory Commission (FERC) is reviewing or has approved eight projects since 2011, each worth tens of millions to hundreds of millions of dollars.

Kinder Morgan’s Cochin Pipeline, which runs 1,900 miles from Alberta to Ontario, contacting five U.S. propane terminals along the way, is an example. Despite the line’s capacity of more than 70,000 barrels a day, average flow rates of propane out of Fort Saskatchewan, Alberta, into the U.S. have ebbed to fewer than 20,000 barrels per day, with more declines expected.

The line and associated terminals were struggling to compete with U.S. shale production, including the 25,000-barrels-per-day increase in Bakken propane production from liquids-rich Bakken natural gas over the last two years. “Cochin didn’t have a bright future in propane service,” says Karen Kabin, director of business development for Kinder Morgan’s Products Pipelines.

Now the company plans to reverse Cochin’s flow, boosting capacity to 95,000 barrels of condensate per day to serve as diluent for the heavy oil sands bitumen. Kabin says 90% of the capacity has been committed. The $260- million converted line is set to be in service by July 2014.

“When you look at the possibility of having firm capacity being taken out for the next 10 years at 95,000 barrels per day, that’s a much better use for the system,” Kabin says.

Natural gas flows

Natural gas plays—first the Barnett shale and now, the Marcellus, have also changed the resource map and the complexion of natural gas pipelines.

From 2009 to 2011, Pennsylvania’s natural gas production more than quadrupled to 3.6 billion cubic feet per day, according to the EIA. In 2012, production vaulted by 69%, averaging 6.1 billion cubic feet per day, according to the Pennsylvania Department of Environmental Protection (DEP).

“When the Marcellus bloomed, that had implications for the existing pipeline infrastructure,” Reichman says. “Supplies have now developed closer to some demand centers, which rendered some of the existing pipeline infrastructure obsolete.”

Midstream companies have responded at a steady pace. For example, Tallgrass Development LP, Overland Park, Kansas, is reconfiguring a natural gas pipeline, the Pony Express, to transport domestic light crude from the Bakken and eastern Montana to the Cushing, Oklahoma, hub. The 24-inch pipeline is a mix of converted natural gas pipeline and new construction. It is slated to be in service by August 2014.

In 2012, FERC approved a reversal of the Elba Express Co. LLC Elba Express to flow south. The 200-mile pipeline, now in service, is owned and operated by El Paso Pipeline Partners, a Kinder Morgan subsidiary. It extends from the Elba Island LNG terminal near Savannah, Georgia, to the Transco pipeline in Hart County, Georgia, and Anderson County, South Carolina. And in July 2012, Energy Transfer’s Trunkline Gas Co. LLC submitted a proposal to FERC to transform an underutilized gas pipeline to carry crude oil. The line would transport crude oil from the Midwest to the Gulf Coast, particularly refineries in Louisiana.

Most recently, in early May, Columbia Gas Transmission filed an application to reverse the flow on its system to carry Appalachian production to Southwest markets.

Permian basis

Even areas used to massive oil production have been stunned by recent growth. Permian Basin oil flow represents a fifth of U.S. oil production—so much that changes in how it moves can alter the price. The trick is getting that oil out.

The basin returned to 1 million barrels of daily production in 2011, the first time in more than a dozen years. Historically, much of the crude was transported via two pipelines to storage at Cushing. But bottlenecks there have amplified, even though pipeline capacity to the hub has increased by about 815,000 barrels per day in the past three years, as production has flowed into the hub from the Permian, Bakken, Niobrara and other plays with no matching increase in pipeline capacity out.

Now, the Permian faces the same hurdles as other high-producing areas. Its lines are at or near capacity. Industry forecasts suggest already formidable Permian production could increase by another 800,000 barrels a day by 2016.

The midstream sector’s response? Reverse, expand and convert six pipelines by 2014. The projects would add 830,000 barrels a day of capacity headed to the Gulf Coast region. Most of that new capacity heads directly to the Gulf Coast rather than northeast to Cushing.

Midstream companies see a golden opportunity in the Permian. Magellan Midstream Partners, for one, has played a major role in opening up the Permian to the Gulf Coast. Earlier this year, its 18-inch Longhorn pipeline project began delivering an average of 90,000 barrels per day to the Houston market, from mid-April through the second quarter.

But there’s also risk.

“When you look at the landscape of supply and demand, there are a lot of different players,” Reichman says. Refiners want the cheapest source of crude, producers seek the best market, and midstream companies chase firm supply commitments.

“Really what you’re doing is trying to have a better-balanced market in terms of matching the supply with demand sources,” he says. The risk is that the market will become oversupplied, similar to what happened in the natural gas markets—but at present, he doesn’t see that developing. There’s a very real concern that the Cushing glut will become a Gulf glut, however.

Though take-away crude capacity is ramping up, Magellan’s Mike Mears, chief executive officer, said during an earnings call in early May that he isn’t concerned about companies overdoing it. “I think if you look at the most recent production forecasts, five to eight years out … there’s not enough take-away capacity with projects being currently built,” he said.

“We don’t think the market is overbuilt. We think there’s potential for increased take-away capacity over time.”

Magellan spent $375 million to convert and reverse the Longhorn refined petroleum products pipeline that flowed from Houston to El Paso. The system now runs crude from the Permian Basin to Magellan’s terminal in East Houston. Mears says he expects full capacity of about 225,000 barrels per day to kick in during third-quarter 2013.

“The Longhorn pipeline is fully committed, but we have allocated 10% for spot shippers, which has been well-received by the market,” he says.

The company is considering expanding the pipeline’s capacity by another 50,000 barrels per day, to 275,000. “Speed of execution is imperative,” Mears says. “We expect to make a decision on this project within the next few months. For now, this project remains in our bucket of potential projects we are assessing that well exceed $500 million in total.”

By 2014, Permian production is expected to increase 6% to at least 1.37 million barrels per day. New capacity is vital to get that product to market. The most logical destination is the Houston area with its big complex of refineries and petrochemical plants, says Magellan spokesman Bruce Heine.

Magellan and Sunoco Logistics Partners LP are largely responsible for several pipelines set to come online later this year and in 2014. They feature reversals, expansions and new lines.

Sunoco has invested in improvements to reconfigure a number of existing pipelines extending from Wichita Falls, Texas, to Nederland, Texas. The Permian Express Pipeline enables crude at Wichita Falls and Ringgold, Texas, to push to a terminal in Nederland, east of Houston.

“With the use of pipe already in the ground, Permian Express Phase I offers West Texas producers and Gulf Coast refiners a fast and cost-efficient solution with tremendous operational flexibility,” says Michael J. Hennigan, Sunoco Logistics’ president and chief executive officer.

In May, Sunoco said it was conducting an open season for the Eaglebine Express pipeline, which would involve converting a portion of its existing refined products MagTex pipeline into crude service and reversing the flow of the pipeline from Hearne, Texas, to Nederland.

In January 2013, Enterprise Products Partners LP and Enbridge Inc. completed a reversal of a 500-mile, 30-inch pipeline between the Cushing hub and Freeport, Texas. The Seaway Crude Pipeline previously moved oil imports from Gulf Coast to Midwest refiners; now it moves oil out of the Cushing bottleneck and into the Houston area. It can carry about 400,000 barrels per day of light and heavy crude oil.

These reversals, expansions, and new lines are freeing up outbound capacity at Cushing and will provide about 833,000 barrels per day of new capacity to the Gulf by 2014, according to the EIA.

The effect on oil prices

Already, increased coastal access is having an impact on oil prices. Early May saw the WTI-Brent spread fall to the lowest level since prices began to widen in January 2011, says Stefan Wieler, an analyst with Goldman Sachs.

“The main driver for this shift is the completion of several pipeline projects [Permian Express, Longhorn and West Texas Gulf Expansion] that now allow sending 0.2 million barrels per day of crude from the Permian Basin directly to the refineries in the Texas Gulf Coast rather than to Cushing,” Wieler says. “However, eventually the [U.S. Gulf Coast] will become saturated with light sweet crude.”

Many of these projects are headed to Houston, where pipeline and terminal capacity in the Houston refining center are increasingly constrained.

“When you factor in the growing Permian production and Eagle Ford and all the rest of it, it looks like Houston is really going to be swimming in oil,” NuStar’s Anastasio says. “That’s the advantage we have of having Corpus Christi as our focus of attention right now.” Corpus Christi is a secondary refining hub to Houston on the Gulf Coast.

Kinder Morgan’s Project Freedom Pipeline, a planned gas-to-oil pipeline conversion, would have run 740 miles from Midland, Texas, to California, at a cost of $2 billion. However, producer interest has been thin and the company announced in June it was postponing the project—and would pursue crude-by-rail options instead.

“Somebody has to sign up for the space,” Lindley says. “That’s the way we did KMCC. That’s the way we did Cochin. Kinder Morgan is not going to step out and do a $2-billion deal unless a producer or a refiner or a trading company or somebody that wants that space signs up for enough capacity to make that an economic project.”

At press time, the Wall Street Journal reported that major West Coast refiners Valero, Tesoro and Phillips 66 did not believe the proposed $5- per-barrel tariff for the pipeline could compete with crude by rail from the Permian and barges from Canada. The companies said rail and barges delivering crude from North Dakota, Canada and Texas would afford more flexibility.

A costly build-out

“The timing and expense of this infrastructure build-out, it’s going to be over decades,” Verrastro said at IHS CERAWeek. “So even if this oil is available, if we have no place to put it or can’t get it out or it’s limited by export restrictions, it won’t get developed.”

Even relatively small projects cost a lot. Holly Energy Partners’ southeast New Mexico project entails converting a refined products pipeline to crude oil service. After construction and reactivation of some crude oil pipeline in the Permian Basin, it will connect to a main line.

“I think they were planning to spend $35- to $40 million and would increase capacity across the system by about 100,000 barrels per day,” Reichman says.

NuStar notes that between reconfigurations, reversals and new infrastructure, it may spend as much as $1 billion on pipeline projects.

Still, having an underutilized pipeline that can swing in the right direction or change what it’s carrying is a cost-saver. “When you look at the math, converting a gas pipeline to crude is way less expensive than building from scratch,” Fielden says. “It’s a whole lot less hassle to convert an existing pipeline and not disturb the earth in any way, than to have to dig a new hole in the ground and address permit and right-of-way issues.”

Some red tape persists, however. Fielden notes that FERC must sign off on changes to interstate gas pipelines to ensure that decommissioning a pipeline won’t cause higher prices. And, conversions may involve some new-build construction, requiring new permits and evaluations.

The process of conversion is cheaper, but not cheap. TransCanada, for instance, will disconnect its pipeline from the natural gas network. Then it will clean 1,900 miles of pipe. After any repairs, an electronic leak-detection system will constantly monitor pipeline operations. Shut-off valves have to be installed every 30 kilometers (18.6 miles) and near sensitive areas such as river crossings, Cannon says.

Gas compressors must be rebuilt as oil pumps and new pipeline are added to connect to producers and refineries, RBN’s Fielden says.

Companies that lack the financial muscle of a TransCanada will have to find support elsewhere. Recently, the marketplace has seen a proliferation of midstream infrastructure companies taking advantage of the tax-efficient master limited partnership (MLP) model.

“This MLP thing has been around for some time, but it just so happens that in an age when there’s a lot of need for, effectively, new plumbing or infrastructure to realign the flows of oil and gas, a lot of investment money has been attracted to MLPs,” Fielden says.

Many midstream operators are moving to more stable, fee-based “toll” business models, rather than percent-of-proceeds service contracts where revenues vary with the prices received for the commodities handled.

“A lot of large midstream energy companies have reorganized their assets as an MLP, because it is tax-efficient and can attract market investment for infrastructure,” Fielden says. Investing money to repurpose even part of a pipeline makes sense because it will increase revenue, he adds.

Lindley notes that Kinder Morgan sees the backlog of projects happening everywhere. The unknown will always be where to build.

One producer the company has been talking with for two years thought its Eagle Ford production standpoint would be 30,000 barrels a day today. “In fact, they’re at 80,000 or 90,000 barrels per day,” Lindley says. “They’re all dealing with uncertainty, but what they do know for certain is they want to get barrels to market as dependably and cost effectively as they can.”