Power generation will continue to grow in importance to the natural gas market. Reliably connecting gas supply to power plants in the years ahead will take more than synchronizing the gas and power days; a capital-intensive infrastructure buildout is necessary, as is new thinking on the part of pipelines, industry executives said in Houston last Thursday.
By 2037, gas-fired power generation will supply more than 51% of the U.S. power market, up from about 25% today; and by 2037, power market will be about one-third larger than today, according to Black & Veatch’s latest Energy Market Perspective.
FERC has been working on gas-power synchronization issues over about the last 18 months. On Thursday the Federal Energy Regulatory Commission issued a draft notice of proposed rulemaking that would allow pipelines and electric transmission operators to share nonpublic operational information. The proposal is the first concrete step the Commission has taken toward coordinating the two markets (see related story).
The gas-power coordination discussion has included much talk about synchronizing the gas and power days (see NGI, April 29). The gas day is a 24-hour period that starts at 9 a.m. CT, while the power day is 24 hours starting at midnight local time. “There’s already a disconnect” between gas and power because of this, said independent power producer Calpine’s Jay Dibble, director of natural gas regulatory affairs. Further, day-ahead scheduling is not synchronized either, he said.
And on top of that, the laws of physics dictate that power moves in virtually an instant and natural gas doesn’t. “You’re always going to have to have advanced nominations by the gas industry to estimate what’s going to happen in the real-time power market,” Dibble said at an Energy Bar Association (EBA) luncheon.
To address the gas day disconnect, Dibble suggested moving up its start time to 5 a.m. or earlier, which would allow a single gas day to encompass all of the peak demand hours on the power generating side. Then if you push the timely nomination cycle on the gas side further into the afternoon while moving day-ahead bidding up on the power side, “then you kind of flip-flop those two schedules from what they are now,” Dibble said. “As a generator, you’re going to actually know what your day-ahead instructions are before you go out and try to buy fuel, so it’s a better, more efficient method for us [power generators].”
However, Dibble admitted that shifting schedules is not a silver bullet and entails its own difficulties. “One of the things you’re doing is your just kind of shifting the risk from one set of issues to another,” he said. “I don’t know how this is going to impact all those other users on the pipeline that aren’t electric users…If you try standardize the energy day, which one do you pick; do you pick the gas day or the power day? If you pick the power day, which one do you pick, eastern time, central time…? Tweaking, as we have proposed, the start of the gas day, may result in operational folks having to go out in the field before the sun rises…”
And Dibble also said changing up schedules is just the start of addressing the gas-power coordination issues that will only grow larger as gas-fired power generation takes more market share from coal and is increasingly called upon to backstop intermittent renewable power sources such as solar and wind. “There is no doubt that if gas demand continues to grow at the pace that we’re talking about, we’re going to need more infrastructure,” he said.
Also a panelist at the EBA event, Black & Veatch’s Rick Porter, director of natural gas regulatory advisory services, said too much attention in the coordination debate has been paid to the timing of the gas and power days. “Everybody’s talking about the gas day…’All we have to do is make the gas day and the electric day the same and we’ll all go home and be happy…’ I think it’s a big distraction,” Porter said. “You start talking about this and you just get lost in the weeds and you ignore the really important stuff.”
Some of that stuff is the hydraulic parameters of natural gas pipelines, some of which were put in the ground generations ago and are now being called upon to serve a whole new supply and demand outlook thanks to shale gas plays and gas-fired power.
“They were designed as basically steady-state systems, and that’s just a fact,” Porter said. “Over the years, the services and systems have been tweaked a little bit to provide a certain amount of flexibility. But redefining the gas day isn’t going to change pipeline hydraulics. In order to serve the kind of power generation load that we’re talking about serving, there’s going to have to be a significant investment in new infrastructure.
“There’s going to have to be a whole rethinking of the way pipelines operate. That’s going to require a lot of capital, and it’s going to require a lot of time and investment on the part of pipelines and everybody else in the industry. And it’s going to require things way beyond the scope of thinking just realigning the gas day.”
The traditional value proposition of pipeline capacity — moving gas to a location where it can be sold for a higher price — has largely evaporated. As basis differentials across the country have been crushed, gas trading shops have closed up and the value of market-area gas storage capacity has declined.
“At some point you’ve got to establish some other intrinsic value in your pipeline capacity beyond basis,” Porter said. “If you’re satisfied with basis as the value of your pipeline capacity, you might as well shut the doors and go home now because there isn’t going to be any basis for a long, long time since you can get gas all over the country, and there’s just no spread.”
In the flat basis era, pipelines can add value to their capacity by redesigning existing services to make them more flexible to suit each system, Porter said. “You just have to understand what the pipeline business model is about and the markets that you’re trying to serve and the end point you’re trying to get to,” he said.
According to Black & Veatch’s latest survey, 40% of power utility respondents said they were either neutral, “un-confident” or very un-confident in the pipeline capacity serving their regional power grids. “If you as a pipeline can find a way to design services or expansions or whatever, so that you can deal with that issue, then there should be some value to that for you as a pipeline,” Porter said. “That’s something that every pipeline needs to be looking at in order to find some way to add value to their capacity.”
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