Power generators in the Northeast and Southeast last week said they believed changes in the no-bump rule for interruptible transportation (IT) capacity on interstate gas pipelines, to the clearing deadline for the day-ahead market and improvements to the gas infrastructure would go a long way toward improving reliability and coordination of the markets in the two regions.
At a Federal Energy Regulatory Commission (FERC) technical conference on Southeast coordination issues in Washington, DC, last Thursday, Valerie Crockett, senior program manager of regulatory and policy for the Tennessee Valley Authority (TVA), said the TVA was "more than happy" to pay the higher price for firm transportation capacity to ensure reliability, "but we expect to get what we pay for. And under existing nomination timelines and policies, we don't get what we pay for and that's the problem." The TVA provides power to nine million customers in seven southeastern states.
Crockett and other power executives called on the Federal Energy Regulatory Commission to review its no-bump rule for IT service, which states that a shipper that is currently flowing gas on a pipeline cannot be bumped (lose its capacity) because another shipper with a higher priority (firm transportation) has decided to increase its receipt of gas.
"At a certain point of the day if our generation is not already up and running, flowing IT cannot be cut or bumped in order for us to get our FT contracts flowing. That's a problem. We support the pipelines. We want to buy firm transportation, but then it winds up sitting idle. It's a hard message to continue to sell to senior management that we need firm transportation for gas-fired generation if it's really taking a backseat to interruptible that happens to be in the queue before us. That's an issue that I'm facing every day."
Donald Sipe, an attorney with the law firm PretiFlaherty, urged the Commission to use caution if it decides to review the no-bump rule. "Even though it may be frustrating to have firm service and [then see an] IT user who put in a reservation ahead of you who can't be bumped, there is nonetheless an economic value in having that infrastructure not setting idle and have it available for someone to use on an interruptible basis," he said.
"So the existing no-bump rule...needs to be looked at not just in terms of just whether or not it's just easy for electric generation to run, but there's an overall economic calculus that we hope the Commission is going to take into account."
Sipe said he wants reliable service just like everyone else, but he wasn't sure how much consumers would be willing to pay for it.
The current bumping deadline for IT service was instituted back in the mid-1990s when the energy business was structured around citygate deliveries, Crockett said. "That's not the case anymore. I truly believe that we need to take a look at changing some of the standards that we operate under. As a business, at 5 p.m. (central time), as far as my last cut-off [if] IT is flowing, there is still 15-16 hours left before the next gas day starts. I'm still in that intraday mode. There is a lot [that can] happen between 5 p.m. tonight and 9 a.m. tomorrow.
"I understand that IT wants to have a level of confidence, but maybe the IT should look at picking up some balancing operations and let the FT use their FT," she said.
Gerry Yupp, senior director of wholesale operations with Florida Power & Light (FPL), also cited scheduling problems with pipelines. "We have become more and more gas dependent and with the low cost of gas, we're 70% gas-fired generation in a typical month. It is very difficult on a daily basis, as weather changes, [to make] adjustments to our gas schedules, purely because we have a lot of large combined-cycle units."
He said FPL receives natural gas from the Florida Gas Transmission (FGT) and Gulf Stream Natural Gas pipelines. "We have almost 2 Bcf of firm transportation capability: roughly 700 MMcf/d on Gulf Stream and 1.3 Bcf on FGT. Over the last couple of years we [have used] our storage facilities much more than in the past."
The Southeast region -- which includes 10 states from Louisiana and Arkansas to North Carolina -- has an installed generation capacity of 288,567 MW, of which 45% is natural gas. In 2010, the last year for which figures are available, 1.06 million GWh of power was actually generated in the region. More than half of that was produced from coal, while natural gas fueled only 24% of the generation, according to a FERC report titled "Electric and Natural Gas Infrastructure."
However "given the development of the abundant gas shale reserves in the Southeast and in Texas and Oklahoma, we can expect the gap in gas and coal to close as gas prices prices and coal prices approach parity...and as the uncertainty over carbon emissions regulations remains," said Jeff Wright of FERC's Office of Energy Projects.
FERC projected that the generation capacity additions in the Southeast in advanced development and under construction will total 19,374 MW by 2020, of which 48% will be gas-fired plants. Currently, the agency said power generation comprises a little more than half of the gas consumption in the Southeast. By 2020, it expects the sector to account for approximately 60% or the region's gas demand.
Michael McMahon, senior vice president and general counsel with Boardwalk Pipeline Partners LP, said Boardwalk worked with TVA to develop an enhanced nomination service to respond to some of its concerns. "Rather than changing nomination [deadlines], we manage them...We sit down with each of the customers and say, 'what is it that you need,' and then we try to design a service, or enhance a current service or create an add-on."
Melissa Casey, director of Transportation Services/1 Line for Williams Gas Pipeline-East, said services also are being offered on Transcontinental Gas Pipe Line (Transco) to accommodate generators. For one, Transco is providing a service that would allow generators to come in before the gas day or during the gas day and put in a contingency-type request for their firm service.
If at the end of the day a generator did not need the service requested on a contingency basis, it would be provided on an IT basis to customers that would need it to stay out of any kind of penalty situation, she said. The company is also offering a new firm delivery lateral service, Casey said.
At a conference in Boston last Monday on gas-power coordination issues facing the Northeast, FERC Commissioner Cheryl LaFleur said that region "is facing the issues of gas/electric interdependency more sharply and with more urgency than any other region due to [its]...strong dependency on natural gas both for electric generation and for home heating and other end uses." .
Ann Berwick, chair of the Massachusetts Department of Public Utilities, echoed the sentiment. "We in New England feel the gas and electric problems with particular urgency. We hope it's not true, but we're concerned we may be the canary in the coal mine. On the bright side, we canaries work especially well together. The Northeast states are used to highly functional regional cooperation [on] various energy issues."
The New England Independent System Operator (ISO) has taken the leadership on the coordination issue so far, but Elizabeth Miller, a commissioner of the Vermont Department of Public Service, called for action from the industries and states. "It's clear that the ISO alone cannot come to the solutions [for] the region by itself," she said.
The Northeast region -- Connecticut, Rhode Island (RI), Massachusetts (MA), New Hampshire, Vermont and Maine (ME) -- has an installed generation capacity of 37,943 MW, of which 45% is fueled by natural gas supplied by interstate pipelines, liquefied natural gas facilities and from Canada. The largest regional consumers of gas for generation are RI (98%), MA (59%) and ME (51%).
James Ginnetti, senior vice president of external affairs and markets for EquiPower Resources Corp., said his company supports a proposal by ISO New England to change the deadlines for the day-ahead market. As it stands now, he said, a generator like EquiPower has to buy its gas somewhere between 9 a.m. and 10 a.m., then bid into the day-ahead market at noon, in advance of scheduling capacity on an interstate gas pipeline ( nomination deadline of 12:30 p.m.) and knowing whether or not it has been scheduled to provide power the following day.
The ISO is proposing to make the day-ahead market deadlines earlier so that generators that have been committed to run the following day will have time to meet the natural gas market deadlines for buying gas. The proposal also will help power system operators know exactly which power units will actually have the fuel they need to run the following day, the ISO said.
Under the current timelines, EquiPower and other generators in the Northeast do not find out until 4 p.m., when the day-ahead market clears, "whether they bought maybe the right amount of gas, maybe too little [or] maybe too much. If [there is] either too little or too much, they have to go into a relatively illiquid market and either buy more or sell what they over-bought.
"We think it's [ISO's proposed change] a big improvement. [It] would help us know our commitment in the electric market before we have to go out and buy our gas and then schedule it timely at 12:30 p.m. [Eastern]. We think that's a much better use of the limited infrastructure pipeline that we have," Ginnetti said.
With the existing bidding and scheduling system, the risks are on the volume side rather than with prices, he noted. The change proposed by the ISO New England would carry with it "some price risks." Northeast generators are split as to what is the "bigger evil" -- the price risk or volume risk. Ginnetti said his company supports the ISO New England's proposed scheduling change to day-ahead market.
While scheduling is a pressing coordination issue, "we think it's more of a physical infrastructure issue," said John Rudiak, director of energy services for Connecticut Natural Gas Corp. and Southern Connecticut Gas Co. He noted there is only 2.7 Bcf/d of forward haul pipeline capacity into the region, which has led to significant constraints.
He noted that Algonquin Gas Transmission last winter had 100 days of restrictions on its system, preventing the scheduling of gas. Tennessee Gas Pipeline also had restrictions on its system in New York 99% of the days last winter. Rudiak said that Tennessee in the last five quarters has reported 30 operational flow orders, 24 of which were directly related to gas usage in power generation.
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