Discussing FERC Order 1000 and lessons learned from previous closed-end solicitations, Ken Collison, vice president – Energy Advisory Solutions with ICF International, noted on May 5 that it is “very difficult to beat an incumbent, but it’s not impossible.”
As noted in his presentation during a panel on Order 1000 as part of TransmissionHub’s TransForum West held in Denver, other lessons learned from previous solicitations include:
- The team needs to be highly qualified in terms of rights of way (ROWs), engineering, construction and O&M, for instance
- Domestic and state experience may count more than overseas work
- Bidders should detail risks to costs/schedule, with mitigation plans
- Very early completion commitments may not count for much
His presentation further noted that while RTOs have for years developed transmission plans, selecting projects worthy of development, now RTOs are identifying needs – reliability, congestion and policy – qualifying applicants and soliciting bids, as well as awarding the right to develop, own and operate projects. That greatly expands the universe of who can “play in the transmission sandbox,” with major projects up for grabs, the presentation added.
Collison discussed where the industry is headed. As noted in his presentation, for instance, there are more interregional merchant opportunities; there is an emergence of M&A among transcos – spinoffs and acquisitions; and there is a rising importance of a clear transmission strategy.
Collison also addressed non-transmission alternatives (NTAs), such as “energy efficiency, demand response [and] distributed energy resources [DERs].”
According to his presentation, some states require the study of NTAs when seeking approval for large transmission projects, and Order 1000 requires consideration of NTAs in regional transmission planning. DERs, including distributed rooftop solar PV, provide capacity on the supply side during periods of need, and thus are NTAs, his presentation added.
“When it comes to non-transmission alternatives, it’s becoming more complex to analyze these things,” Collison said.
As noted in his presentation, it is important to objectively measure the benefits of transmission and NTAs.
His presentation noted, among other things, that whether an NTA can offset or defer transmission depends on the reliability concern and solution type.
Concluding, Collison said, “There’s no one-size-fits-all solution, so each has to be analyzed.”
Another panelist, Charles Adamson, principle manager – T&D Major Projects with Edison International’s (NYSE:EIX) Southern California Edison (SCE), said during the panel, “To us, it does appear to be a very level playing field, so I think it’s probably a different perspective between the new entrants and the incumbents.”
He noted that incumbent strengths include local relationships; project experience in that “they’re usually able to show that they’ve done some work recently …; their reliability record is usually pretty good; they typically have the financial strength; and they also have the O&M experience, equipment and personnel in the area to keep up the ongoing maintenance on the facilities.”
He continued, “For me, this list is not going to get us very far as incumbents,” adding that if a transmission line’s “only reason to be built is an economic benefit …, [then] all of a sudden there is a cost ceiling driven by that economic analysis. It doesn’t matter how good your engineering is, it doesn’t matter how good any of your attributes here are – it really becomes a go-no go.”
A company might be able to show that it can do the O&M for a little bit less, or somehow through its financing structure, it can make its revenue requirement a little bit less, even with a slightly higher capital expenditure, “but at the end of the day, that revenue requirement up against the economic benefit is going to be your go-no go, so whether you’re an incumbent or a new entrant, if you can’t get that cost target, everything else doesn’t matter.”
That is very challenging for incumbent utilities, he said.
As he discussed, and as noted in his presentation, challenges for incumbents include that costs for competitive projects will need to be significantly lower than what the industry is used to, with more efficient designs and increased risk tolerance.
Also, as he discussed, and as noted in his presentation as well, under Order 1000, regional projects – reliability, economic and policy projects – that are more than 200-kV are subject to competition, while local projects that are less than 200-kV, as well as upgrades to the existing system, are not subject to competition. Also, SCE is obligated to build projects if a non-incumbent abandons a project – subject to California ISO (Cal-ISO) reassessment of need for economic or policy projects.
He also discussed projects affecting SCE that have gone out for solicitation, including the Delaney–Colorado River 500-kV project, noting that the Cal-ISO “is currently doing the comparative analysis of the … remaining bidders.”
Panelist Brian Thumm, director, regional planning with ITC Holdings (NYSE:ITC), said during his presentation, “As the industry evolves, we think that there is plenty of opportunity in the development space.”
He continued, “We have a unique opportunity here as both incumbents and non-incumbents to look at, holistically, how Order 1000 is shaping up across the country.”
As noted in his presentation, Order 1000 non-incumbent developer reforms potentially open new markets for future expansion.
Among other things, he noted that incumbents do have some advantages, involving ROWs and relationships with local government contacts, for instance. He added that “non-incumbents can develop those relationships.”
Fellow panelist Charlie Reinhold, WestConnect project manager, noted during his presentation that in developing its Order 1000 process, WestConnect had a lot of stakeholder input, with the organization creating “multiple membership categories for entities to join and be on the planning management committee, and actually help make decisions as we move forward in WestConnect.”
As he discussed, and as noted in his presentation, those categories include “transmission owners,” which include Berkshire Hathaway Energy subsidiary NV Energy and PNM Resources (NYSE:PNM) subsidiary Public Service Company of New Mexico, as well as “independent transmission developers,” which includes MMR Group’s Southwestern Power Group.
There are currently no members in the categories of “transmission customers,” “state regulatory commission members,” and “key interest groups.”
As he discussed, and as noted in his presentation, there are various subcommittees involving planning, cost allocation and legal matters, among other things.
His presentation further noted that the proposed WestConnect regional transmission planning process involves developing a study plan; model development; identifying regional needs; defining regional alternatives to meet needs; evaluating and selecting alternatives; identifying beneficiaries and allocating costs; and issuing a regional transmission plan.
“For our current efforts, we are in an abbreviated cycle – a one-year-only cycle,” he said, adding, “It’s taken us a little longer to develop our base transmission model than we had expected, but we do anticipate having that available for our planning management committee to approve in two weeks at its meeting.”
As for the 2016-2017 biennial cycle, he said, “We’ll begin our study plan development in the last quarter of this year and we expect much more robust production cost analysis and powerflow modeling in that full cycle.”
Among other things, he noted that Order 1000 requires each region to coordinate with any adjoining planning regions, adding, “We did get an order, substantially approving that process – it was issued in December.”