In June, 19 electric transmission projects were completed, with an overall investment of $2.2bn, including Public Service Enterprise Group’s (NYSE:PEG) (PSEG) $435m Mickleton to Gloucester to Camden project, Kent Knutson, director of Hub Services with PennWell, highlighted during the Sept. 18 TransmissionHub Quarterly Market Update.
“We haven’t seen that kind of completion activity in the four years since I’ve been involved with the TransmissionHub,” he said, adding that in July, a Central Maine Power (CMP) spokesperson said that the Maine Power Reliability Program (MPRP) was “essentially done.”
Rate recovery policy remains at the forefront of uncertainties in the electric transmission industry as developers weigh the cost of projects and how they will be compensated, Knutson said.
As noted in his presentation, diminishing incentives like lower return on equities (ROEs) could stymie investment.
“[A]t the end of the day, investors need to feel that the transmission [project] is a good investment,” Knutson said during the webcast, adding, “[I]f that doesn’t look attractive, or it becomes [somewhat uncertain], then those investors might look elsewhere to put their money.”
He highlighted such recent happenings as various entities across the United States, including Southern California Edison and the New England States Committee on Electricity, recently filing comments with FERC on ITC Grid Development’s petition involving FERC Order 1000, in which the company is seeking guidance from FERC as to how winning bids will be treated for ratemaking purposes. Also, responding to a request for rehearing that the California Public Utilities Commission (CPUC) filed with FERC, Pacific Gas & Electric (PG&E), a subsidiary of PG&E Corporation (NYSE:PCG), last month told FERC that the CPUC is wrong to challenge the return on equity (ROE) incentive that PG&E receives for being part of the California ISO (Cal-ISO). In addition, earlier this month, DCR Transmission LLC (DCRT) on Sept. 14 filed with FERC a petition for declaratory order for authorization to use certain incentive rate treatments for the approximately 114-mile, 500-kV Delaney–Colorado River transmission line project.
Other challenges in the transmission space involve anemic load growth, the final U.S. Environmental Protection Agency (EPA) Clean Power Plan, fossil fuel plant retirements, and uncertainty surrounding renewable energy tax incentives, Knutson said.
Despite that, however, investment in transmission is at an all time peak right now, he said.
“We’re tracking about $22.5bn in investment [of transmission projects] that [are] under construction right now,” he said, adding that the majority of that is expected to come online during the next couple of years – 2016 and 2017.
Meanwhile, he added, electric demand for the 12-month period ending last May is down, with residential electricity consumption, for instance, down 2.4%.
“That’s not really affecting activity in the transmission market today, but if those kind of trends continue, there will be a lot of projects that will be questioned later down the line,” he said.
A lot of large projects are being completed this year, he said, adding that “2016 looks a little bit better than we saw last quarter [and in] 2017 and beyond, the forecast is somewhat robust, but there’s a lot of conceptual projects that are out there [in] early development stage that it’s going to take some effort to get going.”
Lower load growth and policy uncertainty have prompted the number of new project announcements to slow down, with more of a focus on reliability projects involving aging infrastructure and grid modernization, he said.
TransmissionHub is tracking $140.9bn in planned and under construction projects, representing 41,347 miles – or nearly $10bn less than what it was tracking during the 2Q15 outlook. From 2015-2019, the average investment is $19.5bn per year, he said.
As noted in Knutson’s presentation, the statistics support a robust, but slowing, transmission market. TransmissionHub is tracking $50.1bn investment in high voltage direct current (HVDC) projects, $21.3bn of which are underground and underwater. That is broken down to $14.8bn this year, which is lower than what was previously expected, of which $4bn worth of projects are still under construction; $10.7bn in 2016, of which $5.7bn are under construction; $18.3bn in 2017, of which $10bn are under construction; and $30.2bn in 2018, of which $2.7bn are under construction.
This year, of the 130 projects being tracked, 24 of them cost more than $100m each; in 2016, 30 of the 129 projects cost more than $100m each; and in 2017, 37 of the 115 projects cost more than $100m each.
According to the Edison Electric Institute, Knutson said, $19.6bn is expected to be invested annually in transmission projects from 2014 to 2017.
According to his presentation, transmission drivers include grid modernization efforts; compliance to the Clean Power Plan, which supports a reliability safety valve and regional carbon trading markets; renewable standards and a new National Ambient Air Quality Standards (NAAQS) rule, which could deepen the need for renewable energy into load centers, particularly in California; continued interconnection projects for new generation; and new transmission needed in high growth areas.
States like New Hampshire, for instance, are looking into grid modernization, Knutson said. As TransmissionHub reported, interested parties were to provide comments by Sept. 17 on the definition, or elements, of grid modernization that should be included in a New Hampshire Public Utilities Commission (PUC) investigation on electric grid modernization, the PUC said in an order. Also, as noted in the recently released “The Energy Industry Update” by ScottMadden New York’s “Reforming the Energy Vision” (REV) initiative is setting the stage for increased promotion of distributed energy resources (DER) and energy efficiency.
Transmission project updates of note since the last quarterly update include the Northern Pass project, which, as Bill Quinlan, president of Eversource Energy (NYSE:ES) Operations in New Hampshire, said during an Aug. 18 media briefing, will now have 60 miles of the total route placed underground. Also, Duke Energy (NYSE:DUK) told the South Carolina Public Service Commission in an Aug. 21 notice that it plans to apply in late 2015 or early 2016 for approval of a transmission line to serve its new 650 MW power plant. The application will cover the Foothills Transmission Line and associated substation, needed to augment the company’s transmission capacity in western South Carolina and North Carolina. In addition, earlier this month, construction kicked off on the approximately $225m Big Stone South–Brookings County 345-kV transmission line, which is jointly owned by Xcel Energy (NYSE:XEL) and Otter Tail Power, and estimated to be in service by fall 2017, according to a CapX2020 statement.
According to Knutson’s presentation, the top 2015 U.S./Canada projects already energized through last June include AltaLinkManagement’s 215-mile, 500-kV HVDC Western Alberta Transmission Line; Great River Energy’s 250-mile, 345-kV, approximately $662m Brookings County to Hampton line; ITC Holdings’ (NYSE:ITC) 140-mile, 345 x 2-kV, approximately $510m Michigan Thumb Loop Project; and FirstEnergy’s (NYSE:FE) 119-mile, 345-kV, approximately $151m Glenwillow–Bruce Mansfield project.
The top U.S./Canada projects that are scheduled to come online this year, and that are still under construction as of this month, include PSEG subsidiary Public Service Electric and Gas’ (PSE&G) 50-mile, 230-kV (underground/above ground), approximately $907m Northeast Grid Reliability Transmission Project; BC Hydro and Power Authority’s 153-mile, 500-kV Interior to Lower Mainland Project; and Bonneville Power Administration’s 28-mile, 500 x 2-kV, approximately $200m Big Eddy–Knight Transmission Project.
The top U.S./Canada projects that are scheduled to come online in 2016, and are under construction as of this month, include Edison International (NYSE:EIX) subsidiary Southern California Edison’s (SCE) 250-mile, 500-kV, approximately $1.7bn Tehachapi Segments 4-11; Electric Transmission Texas’ 156-mile, 345-kV, approximately $398m Lobo to Rio Bravo to North Edinburg project; and American Electric Power’s (NYSE:AEP) 76-mile, 345 x 2-kV, approximately $128m Valliant to NW Texarkana project.
Knutson also highlighted the Artificial Island effort in the PJM Interconnection region and associated issues with cost allocation.
As TransmissionHub reported, Delaware Gov. Jack Markell, in a recent filing made with FERC, referenced a “need for change in the process that decides who pays how much for power line construction.”
Markell, in his filing, commented on a case that could set a precedent for FERC’s decision on PJM’s proposed Artificial Island project, according to an Aug. 20 statement posted on his website. Markell supported a complaint brought forth by Linden VFT, an owner of power lines in New Jersey and New York that is disputing another PJM construction plan for similar cost allocation reasons, according to the statement.