If current bullish projections for adding another 5 Tcf of gasdemand nationally over the next 10 years is going to become areality, the pace of merchant power plant development will have toaccelerate and the gas business will have to catch up with it,according to a panel of experts at GasMart/Power 2000 in Denverlast week.
Right now neither of those goals appears a sure thing. BradPorlier, vice president for business development at Duke EnergyNorth America, said he’s unsure that the current gas industry canmeet the challenge, assuming merchant development can overcome agrowing list of hurdles from siting to political issues.
Actions on both coasts — in California and New York — havecast doubts on whether sufficient incentives will fully develop tosupport projected merchant power growth.
“In California right now energy prices are too low to justifynew generation,” said John Stout, Reliant’s Houston-based vicepresident of asset commercialization. “To make a project work inCalifornia you need to establish some of these extra values[ancillary services].”
California regulators over the past two years have changed therules and that “causes a distortion in price signals,” Stout told apacked session at the annual industry conference and trade fair.Those changes, he noted, caused his company to pull back plans toadd about 500 MW of ancillary services into the California market.Even though Cal-ISO recently raised its price cap for this summerfrom $250/MWh to $750/MWh, the economic incentives are stillinadequate.
In the meantime, New York regulators have asked FERC toeliminate ancillary services markets and penalize power plants thatmade money offering these services recently in their state.
Joining his fellow panelists’ assessment that price caps areharmful to the orderly development of new merchant power plants,Richard Carlson a consultant with Sacramento, CA-based HenwoodEnergy Services, emphasized that the caps make it very difficultfor any economic model to work adequately as they complicate priceforecasts.
“Price caps in one market can be a de facto cap in other marketsthrough arbitrage,” Carlson said. “It is hard to predict the leveland the timing of price caps.” A counter to this hurdle is beingprovided, he said, through various “rational buyer rules” that havebeen adopted by the California independent system operator(Cal-ISO) and replicated by others in the East Coast and Alberta,Canada under other names.
Carlson recommended a new economic modeling approach to merchantplants called “real options valuation” to replace the traditional”discounted cash flow” (DCF) approach. In essence, unlike DCF whichCarlson sees as biased toward baseload generating units, the realoptions model give value to an array of ancillary services andother uncertainties of the developing restructured power industry.
The ultimate solution to an orderly market and adequate merchantpower goes beyond the current crop of proposed new plants, Stoutsaid. In the next five to ten years, he said, there needs to bewhat he calls “an influx of demand elasticity technology,” meaningapplications such as microturbines and fuel cells that will beginto shave peaks in the demand curve. “Without a new shaping of theloads,” there will never be a downward pressure on pricing.
Aside from price, actual siting and permitting of newpowerplants is an increasing challenge, Duke’s Porlier said. “It isimportant to get ‘down in the weeds’ at the project level tounderstand where a given merchant plant development is at any pointin time. Land is getting increasingly difficult to find for plantdevelopment. I think we too often circle the crossings where majorelectricity transmission lines and major gas transmission pipelinesmeet. That’s not the end of the story. It is only the beginning.”Among the increasingly complex siting/permitting issues affectingboth gas and electricity infrastructure additions are growingshortages of private land, water and the political will to supportsuch development, particularly in the West and near load centers.
“We have to challenge zoning, challenge special use permits andchallenge people who will not vote for power plants or pipelines,”Porlier said. “State legislatures are increasingly getting moreand more active in the siting process. It is a highly chargedpolitical process now. Their constituents are saying they wantsomething to say about this [new energy infrastructure].
Gas demand is projected to increase by 5 Tcf/year and 210,000 MWof new power plants are expected to be added to the grid. “About60% of the projected new plants are combined-cycle plants, where wehave an opportunity to make margin over a good portion of the year.And about 40% of the gas demand will come from combustionturbines,” Porlier said. “So all of the merchant power plants aregoing to want big time gas supplies at the same time. We all knowwhat this means in terms of increased opportunities….. This kindof gas demand is going to have major implications for all of us —from the wellhead, to processing, to the pipelines, marketers andpower providers.”
Where is all the new gas going to come from? There will be someself-correction to both the discrepancy between power supplies andnew plants proposed as well as between projected gas demands andprojected future supplies, Porlier said.
“Press releases are not the same as actual plants being built,”he added, referring to the continuing stream of new merchant powerplant proposals, each of which can cost up to $20 million just toget to the permitting stage. “Many of the present projects proposedwill not be successful.
“We sort of take it for granted that there is enough fuel thatwill be available, on time, in the right places to allow theseprojects to be built. We’re not so sure, and people here will havea lot to do about it.”
Richard Nemec, Denver
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