Changing gas flows, new pipeline expansions, gas-fired power generation, midstream contract strategies, low gas prices and increasing emphasis on natural gas liquids are the hottest topics being bandied about at the water cooler these days. And in many cases, one issue can affect the others, according to Mayer Brown LLP energy attorney, David Bloom.

"First, as the production of shale gas increases, some pipelines will continue to construct new capacity and see changed gas flows," he says.

"We are seeing pipelines engaged in a very large program of expansions to move Marcellus and Utica shale gas to markets," says Bloom. "We have seen certificate applications filed with the Federal Energy Regulatory Commission (FERC) by a large variety of pipelines for many incremental projects involving both looping of existing lines and some greenfield construction. I think what we are seeing are the pipeline owners responding to the new demands by entering into contracts with both the producers and marketers. Also they are engaging in phased expansion of their pipelines to respond to the marketplace as drilling develops."

Pipeline owners have taken full economic advantage of this increased demand, have been responsive to the perceived requirements for new capacity and have been pursuing these projects aggressively. The industry has seen "a bit of a building frenzy" over the past few years with a promise of much more to come.

On gas-fired generation

Also, the pipeline and electric industries must be ready for the anticipated increase in gas-fired generation. As wind and solar farms affect the requirements for the capacity of gas-fired electric-generating plants on an hourly (or shorter) time frame, the flow through of pipelines must adjust accordingly.

"I think this is one of the biggest challenges facing the U.S. domestic energy industry, due to the demands of gas-fired electric generators—particularly those that are not base loaded but are peaking units whose fuel requirements can vary so much from the characteristics of natural gas pipelines," he says. "At the end of the day, the electric generators want the ability to come on and off the system on very, very short notice, particularly in peak periods."

“I think one of the biggest challenges facing the U.S. domestic energy industry will be meeting the demands of gas-fired electric generators—particularly those that are not base loaded but are peaking units whose requirements can vary so much from the characteristics of natural gas pipelines.” — David Bloom, attorney, Mayer Brown LLP

The generating plant owners do not want contracts that require them to bear the cost of obtaining firm transportation capacity, which can be expensive.

Meanwhile, the physical characteristics of natural gas in the U.S. have become more volatile. Going forward, the qualities could vary daily, based on the basin from which the gas is produced. Thus, depending on gas flows, operating and environmental issues are being created for some gas-fired power generators that prefer gas characteristics to remain within the narrowest possible range.

Bloom adds, "There has been a lot of discussion about this. I think this is an area where a lot more work is going to be required to deal with operational and cost consequences of expanding pipeline systems to meet this load and the financial consequences of who is going to bear these costs.

"During the next 12 to 24 months, the industry will see efforts to resolve this, but at the end of the day, it's about money," says Bloom.

"In question are the costs for the infrastructure required to support electric-generating capacity, as compared to the actual megawatt hours sold at any time. Are the contracts for electric-generating capacity robust enough, and will the structures be flexible enough, to recover some of these costs?" Bloom asks. "Some older generating facilities, whether gas- or coal-fired, must be retired, and this will have a big impact on this issue."

On timing issues

To transport gas to the power generators and other markets, midstream gas companies involved in building or relying on a project would like to see the permitting process move more quickly, but the FERC generally has a good record of processing timely permits for projects, at least within an expected schedule. A project that involves only minor pipeline looping or extensions of existing compressor stations can move along fairly quickly.

"But when it comes to the electric side, I think it is a much more complicated process," he says. "When it comes to electrical transmission lines, there is no singular regulator that has the ability, on a day-to-day basis, to approve the construction of new transmission lines across multiple states." Such diverse approval processes can affect a builder's contracted time for completion.

Also, projects that are planned to span multiple states, to bring benefits to the states where the generating facilities and the consumers are located, might not bring much benefit to the intermediate, or in-between, states, which can become problematic in the permitting process.

"There was an effort in the Energy Policy Act of 2005 to allow the U.S. Department of Energy to step in under certain circumstances, but that process has not gone very well due to legal and other reasons."

Long lead times are particularly needed for coal-fired or nuclear generation, he says. Gas-generation permitting tends to move along rather quickly. Lead times can have a profound impact for companies bound by supply contracts.

"The process used on the electric side is more fragmented, and that tends to lead to more delays," explains Bloom. "A generating facility or transmission line has more visible, day-to-day presence after being constructed and placed into service, whereas a natural gas pipeline tends to be more benign, or out of sight, once it is placed into service. So it is more difficult to achieve the final permits in a timely manner for generating facilities and transmission lines in a timely manner, which can lead to missed contract deadlines."

Understandably, the developers of such projects, which are mostly utility companies, would like to see a more expedited process.

"I think the people who are arguing for more expedition also have to recognize that there are other contingencies that are going to have to be considered. The Environmental Protection Agency regulations will need to settle out on issues directly affecting generators. On the nuclear side, we will get some standard designs approved by the Nuclear Regulatory Commission. Then the process should move along more quickly. But, for the foreseeable future, we will see the permitting process on the electrical side just take much more time than on the gas side."

Most major pipeline projects that go before FERC take about two years from start to finish. Yet, some exceptions exist where local, state or other regulatory agencies have the authority to block a pipeline by denying necessary permits.

Unsung heroes

Some of the unsung heroes in the industry are natural gas producers and marketers that have stepped in to take responsibility for providing financial support for pipeline construction, Bloom says. "They are now entering into long-term contracts with pipelines and accepting that risk to market their supplies in the way that local distribution companies used to do in the past. That means pipelines are now dealing with entities' credit worthiness and they must determine if the oil and gas producers will have adequate natural gas reserves to justify a pipeline. In the past, pipeline owners could rely on a local distribution company to pass through its cost to its rate payers, or customers."

According to Bloom, pipeline owners are managing relationships that are "much more commercial" than they were in the past.

"Credit issues have become more important because projects are supported by 10-, 15- or 20-year contracts with producers, marketers and others. Everyone is continuing to adjust to that. The producers are stepping up and assuming much more risk, and the pipelines are now dealing with these commercial situations without the regulatory safety net that regulated gas distributors may have."

In the past, natural gas pipelines in the U.S. often were designed to move natural gas from one or two primary sources to remote markets. Pipelines would transport natural gas from the Gulf of Mexico, Louisiana, Texas and Oklahoma to Chicago, New England or New York. The pipeline rates were designed to reflect capacity that was contracted and used for these entire hauls.

"As we see it, more gas is entering systems that serve Chicago, New York, or New England from new sources of gas that are closer to the markets being served." Whether it is because of the addition of Marcellus shale gas, or gas that comes from the Rocky Mountains through the Rockies Express Pipeline or otherwise, the physical flows through the pipelines have changed and will continue to do so.

Who pays?

"The questions that now come up are: How do the pipelines recover their costs and how do they design their rates when the use of the pipeline has changed so much? There have been rate cases that have been filed, in part, to address these issues," he says.

Recently, Tennessee Gas Pipeline filed a rate case that has been resolved by settlement. "And other pipelines have filed rate cases where they are trying to ensure that they recover the cost of capacity that is no longer required, or at least not required to the same degree. There are big chunks of pipes that are no longer used in the same way and to the same extent," explains Bloom.

The pipelines want to continue to recover their costs from their customers, he says. Meanwhile, customers want to look at the actual sections of the pipe they use, and to the extent that they are not transporting over the entire length of the system, they want to be absolved of any cost responsibility for those unused sections.

"That's another battle that's going to be fought over the coming years. Generally these pipelines have been entitled to recover their previously incurred expenses. We are going to see some major shifts and I expect that over the next two to three years, we will see a wave of pipeline rate cases in which these issues are fought."

So some customers that thought they were going to be reducing their transportation costs by moving to shorter hauls will find out that their bills will adjust to enable the pipeline to recover its total cost of service, he warns.

On Section 5

"We have seen, during the past few years, that, after a long hiatus, the FERC has been more aggressive in using its powers under Section 5 of the Natural Gas Act to set pipeline rates for review in complaint proceedings," says Bloom.

In those proceedings and others, one party bears the burden of proof to demonstrate that the rates are too high and suggests what the new rates should be. "The FERC's actions have led to a series of settlements and they certainly could lead to some unintended consequences," he says.

"At the end of the day, they may encourage some of the pipelines that have been without a rate case for many years to file new rate cases. The combination of the change in the way pipeline systems are being used, years of investment, and the knowledge that the FERC is obviously undertaking a pipeline-by-pipeline review of those that have not filed rate cases for many years, suggests that we will see more of the pipelines coming in voluntarily so they can take charge of their own futures," Bloom says.

As a result, much activity is expected in rate-case filings, Bloom says. "Life is going to be more active on the pipeline front, whereas for many years there have been relatively few rate cases filed. It's going to make interesting times. A lot of things will be coming together all at once."

On LNG

In addition to changing gas flows and rates, an issue affecting many gas producers' and midstream operators' planning strategies is the new possibility of U.S. gas exports.

"There are going to be a couple of effects from the increase of shale gas production on liquefied natural gas (LNG) facilities," contends Bloom. "Some of the existing LNG-import facilities are being turned into export facilities and new greenfield LNG facilities are being proposed. New infrastructure will have to be built to support those."

As a result, some field lines must be expanded to meet the requirements of the LNG projects, which could produce some additional construction in addition to what Marcellus and other shale gas production have encouraged.

"Revising or adding LNG facilities will also change the gas flows in the U.S. In a sense, this may be a very good thing for the pipelines. If a pipeline has traditionally moved gas from Texas and the Gulf Coast to New England, and now suddenly sees some of that market disappear, the ability to move gas from the southeastern U.S. to the LNG exports might give them a new market that helps them use a portion of the pipeline that otherwise might have faced reduced utilization," Bloom says.

"More than one factor will have to be resolved in the continuing shift of the way that natural gas moves in the U.S." he says. "These changes will have an effect on the way that prices play out, such as the differentials between various basins. So it is just one more piece of evidence that the market is going to have many changes in the next couple of years."

To change the flow in a pipeline, the operator has to go to the FERC, unless it already has the approvals necessary to accommodate new patterns of use of the pipeline to the extent that change in utilization may affect their permits. Bloom says, "They have to take a look at whether their permits require changing. Luckily, to the extent that a company has an existing compressor station and needs to reverse the flow, there will be much less environmental impact than building a new compressor station or pipeline altogether. As a general matter I don't think those particular permits are going to be the critical drivers for timing."

The critical drivers for timing are going to be the approval permits from the Department of Energy for export of LNG to non-free trade agreement countries, and then the permitting process before the FERC, the Coast Guard, or the Department of Transportation, whichever has jurisdiction. "The pipelines are going to have a lot of work to do, but I don't think they are going to be the choke point on this happening."

On gas prices

"During the past few years, natural gas prices have remained relatively low for an extended period of time and are moving farther away from their historical relationship to crude oil prices. One of the ways to address that issue is to place more emphasis on natural gas production in areas of associated liquids, which is a geographic issue," Bloom says.

Today, the liquids are stripped out of the natural gas stream and sold to markets where the prices of the liquids are more closely tied to the prices of crude oil driven products. This presents an opportunity for natural gas producers to continue natural gas production, but also link at least some of the energy content of what they produce to crude oil prices, which are high, compared to today's natural gas prices.

"We are seeing the announcement of the development of the infrastructure, pipelines, processing plants and other facilities in shale areas to make that feasible, so producers are responding in a way to improve their economics and keep their cash flow healthy. It leads to a strong energy industry which, in the final analysis, is a good thing for the economy," according to Bloom.

The profitable price of liquids is giving new vitality to an industry facing low gas prices, and the increased availability of low-priced natural gas and new domestic liquids is providing some vitality to domestic industries that had previously been hit very hard by the disparity between U.S. feedstock prices and the feedstock prices in non-U.S. oil producing areas.

Natural gas also could find new markets in the transportation sector as a substitute for gasoline and other fuels. The holdup on converting trucks that primarily move across the country on interstate highways to natural gas is the lack of a national infrastructure to support the conversions. Gas-fuel infrastructure builders don't want to make an investment until they see firm demand.

Bloom says, "You have a chicken-and-egg problem here. Many people agree that this would be a very beneficial thing for the U.S., but getting companies to make that first investment under the theory if you build it, it will come, can be very difficult. That is why, to date, we have seen more success for natural-gas-fueled vehicles like delivery vans that remain in an urban area, or local buses, because it doesn't take a large number of refueling depots. A bus company or trucking company can build one or two fueling stations that will be sufficient for its local fleet.

Eventually, proof of demand for gas-fueling stations will be needed. "No one wants to go out and build hundreds of fueling stations and then wait five or six years for them to become profitable. It is going to be hard to convince a major trucking company to make this investment unless they are sure their routes are covered. The hope would be that a major trucking company and some interested energy producers would come together within a heavily used corridor to develop a project that has both the necessary demand and the necessary infrastructure."