Big projects mean big risks and big challenges – TransForum West panel

Big projects, whether transmission lines traversing several hundred miles or a super-substation designed to connect the three electrical interconnections in the United States, face big challenges including public opposition, environmental concerns and investment risk.

Experts who spoke at TransmissionHub’s TransForum West in San Diego July 17 agreed that the biggest single challenge is negotiating the regulatory process.

“Permitting is incredibly complicated, markets are shifting [and] jurisdictions are confusing,” Jim Hoecker, former FERC chair and panel moderator said, adding, “There are lots of regulatory factors that can throw grit in the wheels as you’re trying to develop projects.”

Among the big projects discussed was the Tres Amigas Superstation, a large merchant substation planned near Clovis, N.M., designed to take advantage of marketing and arbitrage opportunities between the Western, Eastern, and Texas interconnections. It has been affected by changing market conditions as well as delays in the regulatory and financing arenas.

When plans were first drafted in 2009, peak hour real-time prices in the Texas market “spiked at between $115 and $126 per megawatt between 4 and 4:30 in the afternoon in Texas, where the Four Corners prices [for electricity in] the California ISO market was $40,” according to Ziad Alawan, CEO of ZGlobal and consultant to the Tres Amigas project. The difference between those prices presented a number of opportunities for energy trading.

Since then, however, West Texas has developed more generation and prices have dropped.

“You have 10,000 MW of wind in West Texas and it’s growing,” Alawan said. “You’ve got a lot of hours in West Texas where the [locational marginal price (LMP)] is negative, where they pay you to take the power.”

The project has also faced delays securing the capital needed to start construction.

According to a November 2011 SEC filing, Tres Amigas raised $3m in venture capital that month. The following month, it reached agreement with Mitsui & Co. Ltd., to invest $12m in the project. At that time, the company anticipated beginning construction of the first phase of the project in 2012, with commercial operations beginning in 2015.

In June 2012, the company engaged two New York financial institutions in its efforts to raise $500m in construction financing for the first phase. However, more than a year later, Alawan indicated that those funds have yet to be secured.

“The bankers are telling us we have to make sure we have acquired 70% to 80% of the right of way for [two] lines” that will connect to substations in Southwest Power Pool (SPP) and Public Service Company of New Mexico (PNM) before the venture can obtain the funds needed to build the project’s first phase.

In addition, securing interconnection agreements with those organizations took longer than expected. The company spent about 18 months negotiating interconnections with SPP, Xcel Energy (NYSE:XEL) and PNM.

It is also negotiating agreements with ERCOT for a DC connection in the second phase of the project, and officials anticipate that process will also be a lengthy one.

“It’s going to take about a year to a year-and-a-half to finish the interconnection [agreements],” he said. “One of the challenges here is that it really takes a lot longer than you’d think. ERCOT said they’re going to be done in 120 days; I think it will be more like 360 days based on our experience with SPP.”

A representative of Clean Line Energy Partners, which is planning four long-haul DC lines to move from the wind-rich central United States to the east and west, cited the difficulty of dealing with California when planning transmission projects, particularly for transmitting renewable energy.

“In deciding how to meet its [renewable portfolio standard (RPS)], the California Public Utilities Commission put a spreadsheet on its website with all the calculations of how they decided to meet the RPS,” David Berry, Clean Line’s EVP for strategy and finance, said. Although the process was transparent, he said, the conclusions were wrong.

“It’s not a black box; it’s just that the box is broken,” Berry said, noting that the method for commenting on, and perhaps influencing, the CPUC’s process was unclear.

The developer of another big project, the Cascade Crossing transmission project, said the biggest challenge with transmission in general and the Cascade Crossing project in specific is uncertainty.

“We look at schedule challenges, we look at the permitting processes, we look at the changing standards, regulations [and] the costs for mitigation,” John Sullivan, manager of the Cascade Crossing project for Portland General Electric (PGE; NYSE:POR), told the conference. “The market shifts because these projects take so long. We see shifts in the market, particularly around renewables and load-growth forecasts, and we also see challenges on the regulatory front.”

Cascade Crossing was proposed in 2004 as a 215-mile, double-circuit line that would provide a path for generating resources on the east side of Oregon, including renewable generation, into the PGE service area west of the Cascade Mountains.

PGE intended to parallel an existing Bonneville Power Administration (BPA) easement that extends from the northeast area of the state to Salem, Ore., believing that such an alignment would result in a significant reduction in the project’s impacts.

Although reduced, the impacts were nonetheless significant. The project path crossed two national forests, three wild and scenic rivers, property in the Salem area designated exclusively to farm use, the Confederated Tribes of Warm Springs Indian reservation, and a Department of Defense bombing range.

Wildlife issues also entered into the project plans.

“On the eastern side of the state, we had the Washington ground squirrel, which is in danger of being listed” on the endangered species list, Sullivan said. “On the west side, both through the Willamette National Forest and Mt. Hood, we had the northern spotted owl.”

After PGE submitted its 18,000-page application, which Oregon regulators called “the most complex and voluminous application” they had ever been required to review, BPA identified an alternative that would enable PGE to shorten the line so that it did not have to cross national forests or the Indian reservation.

Those changes led PGE to request that the lead federal agency for the project be changed from the U.S. Forest Service to the U.S. Bureau of Land Management (BLM). That request, Sullivan said, essentially brought the NEPA process to a halt while federal agencies figured out how to make the change.

At approximately the same time, market conditions changed. Load forecasts were reduced, California enacted incentives favoring in-state renewable resources, and BPA was bringing projects online that were relieving constraints in the area’s transmission system. In further conversations with BPA, it began to look like the agency could supply all the capacity that PGE needed.

“We went from a 215-mile double circuit to a 122-mile single circuit 500-kV [project], to essentially no build at all,” Sullivan said.

While it will mean a paradigm shift, Sullivan said the two agencies are working together and it is possible they will arrive at a solution that will enable the importing of the 2,000 MW the Cascade Crossing was designed to handle without the need to build any additional infrastructure.

“As we’ve worked through these complex issues, we’ve decided there is no silver bullet,” he said. “To get a little more certainty around what you’re doing in building transmission is going to [continue to] be a challenge.”

PNM is a subsidiary of PNM Resources (NYSE:PNM)