Building utility-scale PV solar projects is getting tougher. Greentech Media’s U.S. Solar Market Insight conference concluded with a discussion between experienced developers about the challenges and opportunities.

Moderator and GTM Research Senior Analyst Shyam Mehta asked them to first review the last year.

“In summer of last year, the IOUs issued RFPs, the first in over two years,” 8minutenergy CEO Martin Hermann recalled. “More than 70,000 megawatts of applications were submitted. They shortlisted about 2,500 megawatts.”

The ISO queue has dropped from 80,000 megawatts to 50,000 megawatts and utilities are “looking very diligently to see if there are any show stoppers” before signing contracts. In this “tough competition for PPAs,” Hermann said, developers are “monetizing or cancelling their portfolios.”

In three years, explained SunEdison (NYSE:WFR) General Manager Attila Toth, the U.S. solar market will be 50 percent distributed generation and 50 percent utility scale projects. But about 85 percent of the 3.5 gigawatts to 3.8 gigawatts of utility projects “is already spoken for, in the queues and has company’s names written on it. There is a very limited opportunity in the utility segment.”

“It is time to focus our energies toward distributed generation,” Toth said. It is “a very hard market to scale in,” he said. But with rising retail rates, falling costs, and the rush for projects before the federal investment tax credit drops from 30 percent to 10 percent in 2016, “there will be a surge there.”

“A lot of the larger developers went into the small generation interconnection queue,” said Lincoln Renewable Energy COO Dan Foley. “But 10- and 20-megawatt projects are not getting through any faster and transactional costs really hurt small projects.”

“What hurt the industry in the last year is slow load growth because of slow economic growth and low natural gas prices,” objected EDF (EPA:EDF) Renewable Energy VP Kristina Peterson. “A friend calls the 10- to 20-megawatt deals the 'doable renewables,'” she added. “You are right on the transaction costs. But if you have a few of those and a few big ones, you have enough economies of scale in procurement.”

"What else might drive utility-scale PV solar growth?" Mehta asked.

“Two-thirds of the country is in drought,” Foley said. “In those places, where are you going to find 5,000 gallons of water per minute to run a combined cycle gas plant? You’re not.”

In projects below twenty megawatts, Hermann said, “some developers market projects that barely are projects, just documents they try to sell. Others are very professional. Above twenty megawatts, all we do is greenfield, because of transmission interconnections and getting the right location and being sure of entitlement.”

“There is disconnect,” Foley said, “between what smaller solar developers think projects are worth and what they are actually worth. Our preference is greenfield because we like to know where the bodies are buried, although in wind it is such a low cost to acquire some of these projects that you can’t really pass them up.”

Because the wind industry’s production tax credit has not been extended, Toth noted, “tax equity investors that understand how to underwrite large wind assets and don’t understand how to underwrite solar assets are looking toward solar and looking for scalable platforms.” That, he said, “is a big opportunity for solar.”

In Texas, Foley said, merchant wind projects were built without PPAs by independent power producers “backed with bank hedges. Solar is not there but it is close. If it keeps on trending that way and gas goes up, you will see merchant hedges.”

“For merchant to be a reality in solar,” Toth said, “costs need to come down to around $1.50 per watt, gas needs to go up to about $6 per BTU, and we need to get about a $20 per megawatt-hour credit for capacity, to compete with $0.06 or $0.07 wholesale power.”

“We look at solar projects as selling electricity,” explained Hermann. That starts with the interconnection. Before last summer’s California solicitation, he said, his company “picked projects near those substations that would have transmission capacity.” As a result, he said, his company “captured more than a third of the projects that were shortlisted.”

What about financing from panel manufacturers attempting to revitalize their sales? Mehta asked.

“We welcome low-cost capital,” Toth said. “If that comes with some strings attached, we are open to discussing that.”

Mehta said GTM Research foresees utility-scale PV installation numbers for the next three years being strong because of projects in the existing pipeline. But will new project announcements fall off a cliff?

The California projects that will be built by 2016 “are somewhere in the ISO queue,” Hermann said. “There are enough to meet the 33 percent by 2020 requirement and to replace contracts that default.” But, he added, “I would expect a project with good transmission capacity and low cost values to acquire a PPA. The rest will dissolve.”

 “If you don’t have the project in PJM’s queue or the Midwest ISO’s queue or Cal ISO’s queue, it is too late,” Foley said. But there are a lot of other places. ERCOT is a wonderful place to develop. If you want to build in 2016, you can probably find something in 2015 and it will work fine.”