According to PennWell’s Kent Knutson, $12.5 billion were invested in 2013 and the possibility of $14.9 billion in transmission projects is anticipated that will get completed in 2014
Despite plenty of pessimism in the industry among certain subject matter experts, “we’re pretty upbeat on what we see in terms of projects and what’s being planned and what’s driving the market,” Kent Knutson, director of Hub Services for PennWell, said during the April 9 TransmissionHub Quarterly Market Update webcast.
TransmissionHub is tracking more than $164 billion in planned and under-construction projects, he said, adding that transmission remains a highly desired and safe place for investors, particularly for projects that involve a regulated utility and those that file for transmission incentives under the 2005 FERC Order 679 according to which they are granted incentive rates of return.
Of that $164 billion, HVDC projects represent $48.9 billion, while underground and underwater cable projects represent $25.6 billion.
Knutson also noted that $12.5 billion was invested in 2013 and the possibility of $14.9 billion in projects is anticipated that will get completed in 2014. Of that $14.9 billion, however, only $7.7 billion is under construction.
Furthermore, $29 billion is expected in 2015, of which $10.9 billion of those projects are under construction. Additionally, $19.1 billion is expected in 2016, and of that only $2.4 billion is under construction.
He also said that of 114 projects under construction in 2013, 39 costing more than $100m were completed in 2013. This year, there are 145 projects on the book, but not as many large projects. In 2015, there are 163 projects accounted for.
Knutson noted that $12.5 billion in projects were energized in 2013, adding that “this is not to be confused with how much they invested that year, but it’s project valued at let’s say a $100m project that actually came online in 2013, started construction [in] 2012 and some of that was construction work in progress and financed in previous years.”
One significant project that has come online this year is the ON Line project in Nevada, which is owned 75 percent by LS Power and 25 percent by Nevada Energy.
Major projects expected to come online in 2015 are the Western Alberta Transmission Line, the Susquehanna-Roseland project, the Tehachapi project and a couple of significant CapX2020 projects in the Dakotas and Minnesota, he added.
Moving ahead to 2018, major projects that are more conceptual and not under construction include the Champlain to Hudson project, Portland to Hemingway and the Northeast Energy Link.
Knutson also noted that ERCOT has identified $3.6 billion planned in terms of development between 2014 and 2018, and that comes on the heels of the recently completed CREZ build-out.
The top 10 U.S./Canada projects that were completed and operating in 2013 include:
· Edison International’s (NYSE:EIX) Southern California Edison’s 111-mile, 500-kV, approximately $860m Devers to Colorado River project in California.
· Hudson Transmission Partners’ 8-mile, 345-kV, approximately $850m undersea Hudson Transmission Project in New Jersey and New York.
· ATCO Electric’s 217-mile Hanna Region Transmission Development project in Alberta, Canada.
· Northeast Utilities’ 39-mile, 345-kV, approximately $675m Greater Springfield Reliability Project in Connecticut and Massachusetts.
· AltaLink’s 41-mile, 500-kV Heartland Transmission Project in Alberta.
· Knutson also noted that the top U.S./Canada projects planned for 2014 include:
· ATCO Electric’s 301-mile, 500-kV DC Eastern Alberta Transmission Line in Alberta.
· BC Hydro’s 214-mile, 287-kV Northwest Transmission Line in British Columbia.
· NV Energy’s and LS Power’s 235-mile, 500-kV, approximately $552m ON Line Transmission Project in Nevada, which is operating as of this month.
· AltaLink’s 94-mile Cassils to Bowmanton Transmission Project in Alberta.
· Public Service Enterprise Group’s (NYSE:PEG) Public Service Electric and Gas’ 55-mile, 230-kV (UG and AG), approximately $390m North Central Reliability Project.
Effects of distributed generation, weather, generation mix
Knutson also discussed “the utility death spiral,” or the idea that microgrids and distributed generation are “going to take a big chunk of what utilities have today.” However, high profile investors like Warren Buffett continue to invest in the sector; particularly in states that are highly regulated and allow higher return on equity. Buffett’s strategy is to retain earnings and invest in infrastructure and new generation projects, he noted.
Despite the robust view of where transmission is headed, a lot of uncertainty remains, with likely the biggest factor being the U.S. Environmental Protection Agency (EPA) rules on fossil fuel power plants, which mostly entail coal, he said.
On transmission investment drivers, Knutson said: “We’re looking at a low load growth future and it’s driven mostly by improved efficiencies, distributed generation [and] demand side-type management practices. The one caveat in this is that peak demand still pops its head and the market continues to have some volatility.”
Transmission incentives still drive the investment as does aging infrastructure, he said, noting that there are nearly 300,000 miles of high voltage transmission lines in the United States and Canada, as well as 70,000 substations.
FirstEnergy, for instance, announced last November that it would invest $2.8 billion over four years to upgrade lines and substations, among other things. “I think we’re going to hear more and more of that, which continues to be a driver in the market,” Knutson said.
Generation has a big impact on transmission development as well, with natural gas, wind energy and solar power now dominating the generation landscape, he said.
For instance, 91,000 MW of natural gas, or $95.2 billion in investment overall, is planned or under construction. Of that amount, $70.8 billion in project investment is expected in just the period between 2015 and 2017, he said.
PJM Interconnection has $25.2 billion of gas projects either under construction or planned, followed by ERCOT with $12.9 billion. The New York ISO, New England ISO and California ISO (Cal-ISO), between the three, have $7 billion to $9 billion in investment going on, he added.
The changes in generation mix will have effects on transmission, he said, noting that more than 20,000 MW of coal “fell offline between” 2012 and 2013, with more than 49,000 MW expected in the years to come.
Furthermore, the shale gas boom is prompting an increased demand for natural gas, he said, adding, “[Y]ou have more heating because of the lower prices [of natural gas and] there’s a lot of conversion going on, particularly in the Northeast from heating oil to natural gas.”
Weather events affect gas prices and have implications on the power market and transmission, he said, noting there was a spike during January’s polar vortex. FirstEnergy has already announced that 220,000 northern Illinois customers can expect June surcharges of $5 to $15, he said, adding, “[Y]ou do have some pretty big implications on things like this weather and that can drive public opinion.”
Actions by states, RTOs
Also presenting during the webcast, Rosy Lum, chief analyst and editor-in-chief of TransmissionHub, noted that “state activism is something we’ve been seeing a lot more of lately.”
For instance, she noted that Arkansas state regulators have approved Southwestern Electric Power Co.’s (SWEPCO) Shipe Road to Kings River project, but the project requires approval from Missouri state regulators as well since a portion of the line crosses into Missouri. Missouri state lawmakers have pushed back, arguing that the line provides no benefits to the people of Missouri.
According to TransmissionHub data, the 56-mile 345-kV transmission line would connect the new Shipe Road substation in Centerton, Ark., and the planned Kings River substation in Berryville, Ark. The line is needed to meet the additional transmission capacity demands of the growing north Arkansas region. The total estimated cost of the project is $123.3m, or about $102.9m for the line and $20.4m for the new Kings River substation. Although there is no official announced construction date, SWEPCO hopes to have the project in service by June 2016.
Lum noted that in January, the Arkansas Public Service Commission (PSC) approved the project but instead of approving the company’s preferred route, which would have run entirely within Arkansas, it approved a route that runs across the Arkansas/Missouri border, runs for about 25 miles in Missouri and reenters Arkansas before ending at the Kings River substation. Missouri legislators earlier this year proposed legislation specifically targeting the project to stop it from running into Missouri, Lum added. In response, SWEPCO challenged the Arkansas PSC decision and the PSC is expected to respond to that request the week of April 14.
She also noted that at least eight states have proposed right of first refusal (ROFR) laws in the last three years in response to FERC Order 1000, with seven of them actually passing such laws. Order 1000, she said, requires that ROFR language be removed from federal tariff, with the intent being to open up the transmission landscape, which traditionally has been dominated by incumbent utilities, in order to incent competition, drive down prices and encourage innovation.
To comply with Order 1000, regions under federal/FERC jurisdiction like the Southwest Power Pool (SPP) and Cal-ISO have implemented processes to allow not just incumbent utilities but independent transmission providers to bid for projects that the RTOs have selected for competitive bidding in their transmission plans.
Cal-ISO’s competitive solicitation process, for instance, is beginning this month and six projects have been approved, including three substations and various technology-based projects. One transmission line, the Delaney to Colorado River 500-kV line, that was under consideration was tabled and may come up again later this year and be added as an addendum to Cal-ISO’s 2013-2014 transmission plan, Lum added.
SPP is expected to release a needs assessment on May 2 in which it will identify the region’s transmission system needs, she said.