Permitting electric transmission projects can be the largest risk to a project’s schedule, but it also presents opportunity, Daniel Belin, director — Electric Transmission, Ecology & Environment, Inc., said at TransmissionHub‘s TransForum West event held in Denver.
During his presentation in late June, Belin discussed the opportunity to gain efficiency so that certain deadlines — involving renewable portfolio standards, for instance — can be met to deliver power and generate revenue.
For example, he said, if an RPS has a deadline of 2020, and transmission is needed to transport renewables, but the permitting process for a transmission line project may potentially go beyond that date, “what would it look like for a project to be in service by 2020?”
Belin said that “the Great Northern Transmission Line project serves as a really good example,” of how that could be accomplished.
As TransmissionHub reported, Allete Chairman, President and CEO Al Hodnik said in May that the company expects to receive a presidential permit from the U.S. Department of Energy in 2Q16 for the Canadian border crossing of the Great Northern Transmission Line.
The presidential permit would be the next regulatory clearance for the Great Northern project, after a final route permit was issued April 11 by the Minnesota Public Utilities Commission (PUC), Hodnik said during Allete’s 1Q16 earnings call.
The PUC route permit, which followed a Jan. 4 ruling from an administrative law judge (ALJ), largely follows Allete’s preferred route for the project, Hodnik said.
The ALJ decision included a couple of variations on Allete’s proposed Blue Route, an Effie variation and East Bear Lake variation, both of which are near Effie, Minn., and were supported by the Minnesota Department of Natural Resources and communities in the region. Those variations would site the 500-kV line in existing utility corridors, parallel with two other high-voltage lines.
Allete utility Minnesota Power is developing the Great Northern project in conjunction with Manitoba Hydro.
The PUC adopted the ALJ decision, including the Effie and East Bear Lake variations, which make use of existing utility corridors and reduce impact on wilderness areas, forested wetlands and wildlife habitat. To ensure that reliability issues are addressed, “the commission will require that prior to actual project construction, Minnesota Power file a letter stating that the Regional Planning Authority has studied the triple-line configuration as permitted by the commission and determined or confirmed that the triple paralleling of the project area meets all applicable NERC standards,” the PUC said.
Construction of the Great Northern Transmission Line is expected to begin in 2017, Hodnik said during the earnings call.
Minnesota Power has estimated that the total cost of the project would be between $560 million and $710 million.
The project is planned to be in service in 2020, allowing Minnesota Power to send excess wind power over the line to Manitoba Hydro during high wind conditions, with Manitoba Hydro sending excess hydropower to Minnesota Power during low wind power conditions. The Minnesota portion would extend about 220 miles from the Canadian border near Roseau, Minn., to a new 500-kV Iron Range substation near the existing Blackberry substation east of Grand Rapids, Minn.
Belin, during his presentation, noted that the project’s success stemmed from creating efficiency through three elements: pre-application legwork by the applicant; agency cooperation; and environmental impact statement (EIS) team communication.
Of the pre-application legwork, Belin noted that Minnesota Power did “a lot of heavy lifting” before submitting its application to DOE, by, for example, holding many agency and public meetings and receiving public comments.
“[A]nother success on the agency side was that” the EIS was a joint state/federal EIS, he said, noting that the state of Minnesota and DOE had a lot of coordination over a period of time, before the application was submitted, allowing them to develop a relationship and trust, which helped the process.
The third component for project success was communication among the contractors and the agencies, he said.
Belin noted that there are “war stories” to be shared in the industry when it comes to permitting and “how challenging it is, but there are cases where it works and this is one of those cases.”
Also speaking on the panel was Thomas Jensen, partner, Holland & Hart, who discussed two major intertwined policy transformations: permitting efficiency and mitigation.
Those transformations, which have occurred over the last eight years, are driven by, for instance, the economy, energy policy, climate change and climate policy, he said.
As noted in his presentation, measures involving permitting efficiency include the October 2009 “Interagency MOU on Transmission on Federal Lands,” the May 2014 “White House Plan for Implementing Presidential Memorandum on Modernizing Infrastructure Planning,” and the December 2015 “FAST Act Title XLI (aka FAST-41).”
According to a May 2016 publication authored by Jensen and others titled, “Infrastructure Permit Streamlining Under the FAST Act,” the U.S. Congress last December passed, and President Barack Obama signed, the FAST Act. The publication said that the transportation law included new procedural rules for federal agencies to follow in issuing permits for most major infrastructure and other capital projects, as well as authorization for a large administrative apparatus within the executive office of the president.
While full implementation will take time, the authors said in their publication that they believe that certain opportunities may be available to those who choose to bring solid project proposals into the new system early. The publication noted that Title XLI of the FAST Act changes the federal permitting process for major infrastructure and other capital projects in three ways: better coordination of, and deadline setting for, permitting decisions; enhanced procedural transparency; and tightened deadlines for litigation challenging permitting decisions.
Mitigation policy, according to Jensen’s presentation, includes the October 2013 U.S. Department of the Interior “Secretarial Order 3330, Improving Mitigation Policies and Practices of the” DOI; the November 2015 “Presidential Memorandum on Mitigating Impacts on Natural Resources from Development and Encouraging Related Private Investment; and FAST-41.
“All of this efficiency [and] mitigation is occurring against a backdrop of changing law, changing policy [and] changing legislation about climate,” Jensen said.
As noted in his presentation, in December 2014, the Council on Environmental Quality (CEQ) released revised draft guidance for public comment that describes how federal departments and agencies should consider the effects of greenhouse gas emissions and climate change in their NEPA reviews. The guidance explains that agencies should consider the potential effects of a proposed action on climate change, as indicated by its estimated greenhouse gas emissions, and the implications of climate change for the environmental effects of a proposed action, the presentation stated.
Another panelist, Susan Innis, manager, Siting & Land Rights, Xcel Energy, discussed Minnesota’s “Buy the Farm” law and eminent domain in Texas.
As noted in her presentation, the Minnesota law was originally passed in 1977, and until the start of the CapX2020 projects, the statute had rarely been used. Under the law, which was prompted by land acquisition for transmission line of 200-kV and above, a landowner has 60 days after being served with condemnation to make an election.
The landowner, Innis said, could opt to have the utility purchase the entire parcel of land — the entire farm — and not just the portion needed to build an electric transmission line. The law adds a level of complexity to the normal challenges pertaining to right of way (ROW) acquisition, she said.
As noted in her presentation, the land must fit with one of six classifications — all are agricultural or residential; the elected property must be contiguous; and the property must be commercially viable.
As noted on its website, CapX2020 is a joint initiative of 11 transmission-owning utilities in Minnesota and the surrounding region to expand the electric transmission grid to ensure continued reliable and affordable service.
Of the Texas eminent domain law (Senate Bill 18, 2011), Innis’ presentation noted that the law is applicable to all condemning agencies, not just governmental.
The Texas Agriculture Law Blog, an outreach project of the Texas A&M Agrilife Extension Service, said that there are three elements of eminent domain under Texas law: the actor must be the state or a private entity authorized to condemn; the property must be taken for public use; and the landowner must receive adequate compensation for the condemned property.
Innis noted in her presentation that lessons learned for siting and permitting transmission projects include that public sentiment is against eminent domain; areas with significant new development, such as transmission lines, may be experiencing landowner fatigue; and there are increasing pressures for “premium” compensation, as well as landowner requests for annual payments and royalties.
The panel also included Rick Thompson, senior manager — Transmission Rights & Permitting, Tri-State Generation and Transmission Association, Inc., which, as noted on its website, generates and transmits electricity to its member systems throughout its service territory across Colorado, Nebraska, New Mexico and Wyoming.
As noted in Thompson’s presentation, Tri-State’s service territory involves Tribal Land, State Trust Land, Bureau of Land Management land, land managed by the Department of Defense and DOE, as well as land managed by the Fish and Wildlife Service, among other entities.
Complex approvals are required when it comes to transmission permitting, including federal, state, tribal and local processes, Thompson said.
He said that Tri-State has been tracking streamlining efforts that have been proposed over the last several years, including the Interagency Rapid Response Team for Transmission, the FAST Act and the Integrated Interagency Pre-Application Process, which as noted on DOE’s website, includes an initial and final meeting and provisions that would allow project proponents to engage in DOE-facilitated early project information sharing, as well as development of an applicant-prepared environmental assessment intended to inform any subsequent environmental review by federal agencies under NEPA.
Challenges involving the permitting process include that state requirements differ and local government requirements are diverse and just as important, Thompson said in his presentation.
Among other things, he said that solutions include clear, consistent and reasonable federal, state, tribal and local permitting requirements. Other solutions, as noted in his presentation, include acknowledgement and acceptance of differences in providers of electricity, as well as communication and understanding within the industry and among agencies and the public.