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Mid-Atlantic Generators: Don't Mandate Firm Pipe Capacity

Mid-Atlantic power generators last Thursday opposed a suggestion that generators be mandated to commit to firm pipeline capacity to ensure reliable delivery of natural gas and the expansion of pipe infrastructure to serve them. At the fifth and final technical conference on the coordination of natural gas and power markets, some generators also said they viewed shale gas as a doubled-edged sword for the Mid-Atlantic region, supplying it with abundant, low-cost supplies and paving the way for a manufacturing "renaissance," while at the same time putting pressure on an already over-taxed pipeline infrastructure.

"As the shale production has come [online], that's been a great benefit to the U.S., but it's also taking up capacity as more generation comes on. I'm concerned there's not the pipeline infrastructure to support it, and I don't know that we can get it built in time, given the disconnects between the two markets. The gas industry has to have commitments," said Marquerite Mills, vice president of fuel procurement at American Electric Power (AEP) , during the technical conference sponsored by the Federal Energy Regulatory Commission (FERC) in Washington, DC. AEP has traditionally been a coal-fired producer of generation, but it plans to retire 6,000 MW of capacity in the next few years, she noted.

The previous conferences explored coordination issues in New England, the Southeast, the West and Midwest (see NGI, Aug. 27). FERC commissioners also were in the West last week to hear from industry.

In addition to her concerns about the pipeline infrastructure, she called on interstate gas pipelines to initiate "hourly nomination cycles" and for regional transmission organizations to align their timing for awarding bids. Mills said another challenge is that the PJM, one of the two organized power markets in the Mid-Atlantic region (the other one being New York ISO), does not allow generators to recover their reservation charges associated with firm transportation contracts. "If we go out and secure firm transport 24/7, 365 days a year for [the] long term, we really have no mechanism to recover those costs from the markets." This is why many generators are reluctant to sign firm transportation contracts, which pipelines require before they will build new projects.

"As long as the paradigm is such that power generators cannot recover the fixed costs associated with those transportation capacity contracts, there really is no incentive for them to hold it because otherwise they're at risk," said Stanley Chapman, senior vice president of marketing and customer service for NiSource Gas Transmission & Storage. "The question...becomes how do we incentivize power generators to hold adequate amounts of [firm] capacity...How do we change that paradigm going forward and allow generators to get recovery of those upstream contracts?" he asked.

Pipeline executives contend that generators need to commit to long-term firm capacity on their systems to ensure reliability and to underwrite the costs of construction of more pipe facilities to serve them as gas-fired generation market grows. But not all generators agreed with this position. "I don't think the solution is always going to be firm capacity for generators...Dual fuel capability for example is an option. There are other options as well. It's not always firm pipeline capacity," said Scott Butler, project manager of Consolidated Edison Co. of New York Inc.

To support future pipeline construction, "I don't see in every circumstance that you're going to need a generator to enter into a long-term contract. In our area producers, for example, have been sponsoring a lot of big upgrades," he said. He noted that Con Ed has only contracted for 150,000 Dth/d of the 800,000 Dth/d of additional capacity that is expected to come into Manhattan on Spectra Energy's New York-New Jersey Expansion Project in 2013 (see NGI, May 28). Butler said producers have subscribed to the remaining capacity. "And that's not the only project in the area."

David Ciarlone, manager of global energy services for Alcoa and recently named chairman of the Process Gas Consumers Group, expressed concern that enhanced incentives for power generators could affect the price of shale gas. "If we get it wrong and turn the prices and incentives upside down and we drive the manufacturing jobs out of this region...we're doing ourselves a great disservice," he said. Shale gas "gives us a hope of a manufacturing renaissance. We are really excited about that in Pittsburgh...We just have to get this infrastructure and cost of it and the allocation of those costs right, or we can strangle this renaissance before it has a chance to take hold."

John Scarlata, vice president of gas supply at PSEG Energy Resources & Trade LLC, painted a more favorable picture of the gas pipeline system serving the Mid-Atlantic region. "We have found that the pipeline infrastructure is very good and is getting much better with the advent of the shale expansion...With the infrastructure improvements, we have seen a real basis collapse in the region, which I think is overall probably good for the consumer."

He said the infrastructure that will be built on Tennessee's 200 Line to get shale gas out of Pennsylvania is going to be "very good" for generators served by the pipeline system.

Scheduling problems with gas pipelines are more pronounced in the NYISO than in the PJM because the region is more dependent on natural gas. Of the 142,629 GWh of generation that was produced in the NYISO in 2010, 33% was gas-fired. In contrast, coal accounted for 54% of the 832,371 GWh of power generated in the PJM in 2010, according to a FERC report on "Electric and Gas Infrastructure" in the Mid-Atlantic region.

The residential and commercial sectors currently are the largest consumers of gas in the Mid-Atlantic region, but gas usage in the generation sector is increasing to the point where it is expected to be the largest consumer of natural gas by 2020, FERC said. Shale gas will meet most of the region's gas needs by 2020, offsetting declines in production of conventional and tight sands production in the Mid-Atlantic.There will be an increase in pipeline capacity into the region from the Southeast and Marcellus Shale areas.

Coordinating the scheduling deadlines between the power and gas markets remains one of the chief concerns of power generators. Some conference participants advised that good lines of communication between pipelines and generators was the solution. "Our experience has been as long as you got really good communication with pipelines and LDC [local distribution company] pipelines, we really haven't had much of a problem. We can balance. They've [pipelines] given us a phone call saying 'hey, we think you've been drawing a lot. What do you think [is] going to happen in the next couple of hours, so we might route some gas in,'" said Kevin Telford, lead trader at Exelon Corp.

"Talk with your pipeline guys, talk with your LDC folks and develop strong relationships with you suppliers."

Talking to the pipelines, LDCs, marketers and producers who hold firm transportation capacity, as well as committing to firm pipeline contracts and reliable gas supply, "are good things for generators to do" to ensure reliability, said Gary Sypolt, CEO of Dominion Energy.

Moreover, the electric market needs to plan ahead by more than three years, he said. "That's not really enough...to commit to a long-term contract and it's something I would encourage the electric markets to think about."

Earlier in the week FERC Chairman Jon Wellinghoff and Commissioner John Norris traveled to Portland, OR, for the fourth coordination hearing. With air quality regulations changing, reduced coal generation and the upswing in domestic natural gas supplies, a "much different fuel mix" is forming, Wellinghof said.

"With that said, I want to also indicate that this doesn't mean that FERC is looking to do something here. Maybe there are issues we can help with, but we certainly don't want to intrude [on states and the industry] where that would be unnecessary. We are just here to learn and find out what the interface between the gas and electric systems is and if there is any potential future role for us."

Industry representatives underscored the point that gas-electric coordination is particularly important in the West because of the large amounts of large-scale solar and wind power projects are now online, which has added stress to the grid. FERC estimates that 42% of the West's generation capacity will be gas-fired, and nearly 60% of the capacity being added in California is gas-fired. The conclusion is that a "significant" portion of new generating capacity installed in the next 10 years will use natural gas as its primary fuel.

But how do the gas and electric systems accommodate this growth? Procuring pipeline capacity and storage remain key, according to the attendees. The outcome may depend on how diverse (or consistent) are nominations, scheduling and commitment practices across the region, as well as how the region's utilities and generators manage the mismatch between the scheduling and commitment timelines on the electric side in local time and national standard pipeline practices.

Arizona Public Service Co. (APS) representative Justin Thompson said more than half of APS's generation capacity is gas-fired, burning about 46 Bcf annually, but that is expected to grow substantially by 2020, when it hits a forecasted 104 Bcf. "We expect to more than double the gas burn for power during the next six or seven years," he said. "That will add to the volatility of the gas burn for us."

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