Natural gas continues to dominate the electric power industry in the United States, which is facing such challenges as compliance with the U.S. Environmental Protection Agency and power plant retirements, speakers said during the Dec. 9 GenerationHub Quarterly Market Update.
The quarterly webcast was sponsored by Wolseley Industrial Group. The webcast originated from the PennWell POWERGEN-International in Las Vegas.
“Natural gas is taking over really in almost all planning, with the exception of wind and solar,” which are driven more from investment tax credits (ITC) and the like, Kent Knutson, director of Hub Services with PennWell, said during the webcast. “[T]he fate of wind and solar hinges on congressional extension of tax credits … [and] any day now, Congress is going to vote on what’s called the tax extender’s package.”
That is a $95bn package and during the summer, through committee, the production tax credit (PTC) was added to it, he said.
According to his presentation, U.S. investment in power resources from 2016 to 2018 is projected as:
•93.2 GW, or 66%, of natural gas
•23.2 GW, or 16%, of wind
•18.7 GW, or 13%, of solar
Of 141.5 GW of projected installed capacity during that time period, 135.1 GW, or 95%, will be natural gas, wind and solar.
Knutson said, “[T]he reason that 2016 is a big year for solar and wind is [it is] really driven by the production tax credit and the ITC, which promotes and helps solar.”
He noted that stability is important for wind and solar, adding that incentive programs have driven huge growth in those two industries. The cost of wind development and the cost of solar have come down dramatically over time, he noted.
The “industry needs stability because as soon as that expiration occurs on the tax credit, it becomes a driver for industry to shut down … if they don’t see that this is going to be extended, or they’re not sure if they can develop a project,” Knutson said, referencing employee layoffs and less turbine construction.
The ITC is set to expire at the end of 2016, at which point it will revert to the pre-2006 level, which is a 10% incentive. Currently, the ITC is a 30% incentive, he added.
As noted in his presentation, there are plenty of opponents and ideas for phasing out such tax credits.
Also speaking during the webcast was GenerationHub Chief Analyst Barry Cassell, who noted the growth in grid-scale solar power.
LCRA Transmission Services Corp., for instance, filed three interconnection agreements on Dec. 8, including one that involves a 300 MW wind project in Texas, he said.
It is unusual to have three agreements like that filed in one day, but not so unusual in some respects, Cassell said, adding that if there are just these “many projects and all three of those have commercial operation target dates in December of next year, [then there is a] relatively tight turnaround.”
He also noted that companies like Alabama Power and Georgia Power are working on solar power projects on military bases, which ties in with the U.S. Department of Defense’s goals in terms of renewable energy development.
Of the U.S. Environmental Protection Agency’s (EPA) Clean Power Plan, Knutson said that the final version of the plan released this year highlighted “how complicated this is going to be for carbon compliance and the real focus now shifts toward the states,” he said, noting that each state implementation plan can be quite different.
Discussing changes made from the draft to the final versions of the plan, Knutson said, for instance, that the final version extended the interim compliance date to 2022 from 2020.
“The idea there was that needed infrastructure would have a little bit of time to develop, but that’s not a big time frame, particularly for large transmission projects, where it takes six to eight, maybe even 10 years to develop,” he said.
Another change is that the 2030 compliance goal was increased to 32% from 30%, he said.
The initial compliance deadline for the state implementation plans is Sept. 16, 2016, or a “short period of time for every state in the country to really come up with a plan, [an] integrated resource plan [on] how they’re going to meet this and comply,” he said.
There are extensions possible, as much as two years under certain circumstances, he said.
Other changes from the draft to final versions of the plan involve a rate versus mass accounting approach; the inclusion of a reliability safety valve; and the introduction of a Clean Energy Incentive Program (CEIP).
Knutson also noted that 27 states and numerous special interest groups have filed lawsuits against the plan.
Of coal, Knutson noted that power plant retirements hit its peak this year, with about 19 GW retired in 2015, and 2016 is projected to see almost as many retirements as this year, with about 18 GW projected to be retired. Besides coal units getting retired, older natural gas and nuclear units are being retired as well, he said. As noted in his presentation, 10 GW of nuclear may be retired over the next several years.
Knutson also discussed new gas generation projects placed into operation in 2015, including Mississippi Power’s 877 MW Jack Watson plant in Mississippi; Georgia Power’s 807 MW Yates plant in Georgia; and PPG – O&M Panda Temple Power’s 803 MW Panda Temple Power Station in Texas.
His presentation also noted that new gas generation projects expected to come online in 2016 include Dominion’ (NYSE:D) s 1,472 MW Brunswick County Power Station in Virginia; Midwest Generation LLC’s 1,320 MW Joliet 29 plant in Illinois; and Florida Power & Light’s 1,260 MW Port Everglades plant in Florida. Gas generation projects expected to come online in 2017 include Exelon Power’s 1,221 MW Wolf Hollow II plant in Texas; Old Dominion Electric Cooperative’s 1,114 MW Wildcat Point plant in Maryland; and Tennessee Valley Authority’s (TVA) 1,085 MW Paradise plant in Kentucky.
Consolidations, ‘ups and downs of nuclear’
Also speaking on the webcast was GenerationHub Chief Analyst Wayne Barber, who noted, for instance, that there has “been a fair amount of consolidation going on in the energy industry.”
There are various factors connected with that, including that “power companies are becoming gas companies.”
That is, in various states, a number of power companies have natural gas generation coming online and they want to ensure that there are pipelines to serve the new natural gas plants. For example, Southern (NYSE:SO) and Duke Energy (NYSE:DUK) this year bought a controlling interest in companies that have a big interest in natural gas pipelines that will serve many of their plants, Barber added.
As GenerationHub reported in November, Duke Energy is on pace for record natural gas usage this year.
“Additionally, we are taking significant steps to grow our low-risk regulated business mix as highlighted by last week’s announced acquisition of Piedmont Natural Gas, which provides us with additional capabilities and growth potential around natural gas infrastructure,” Duke President and CEO Lynn Good said last month.
Duke expects to close the Piedmont deal in late 2016 or early 2017.
Other “marriage news” include the proposed merger of Exelon and Pepco Holdings (NYSE:POM), as well as NextEra Energy (NYSE:NEE) pursuit of Hawaiian Electric, Barber said, adding that the “big marriage this year, marriage of titans, so to speak, was Alstom and General Electric.”
Barber also discussed other efforts such as the Atlantic Coast Pipeline project. As noted in his presentation, FERC in October issued a notice about a Sept. 18 application from Atlantic Coast Pipeline LLC for authorization to install, build, own, operate and maintain certain natural gas pipeline facilities for its Atlantic Coast Pipeline (ACP) project. Those facilities consist of: about 564.1 miles of various diameter pipeline; three greenfield compressor stations totaling 117,545 horsepower (HP) of compression; and various auxiliary facilities designed to transport up to approximately 1.5 million dekatherms per day (MMDth/d) of natural gas.
Barber also addressed the “ups and downs of nuclear power.” For instance, for the first time in 30 years, there are five nuclear reactors that are going to open soon in the United States. TVA’s Watts Bar 2 unit should start operation early in 2016. Also, four new units are being built in the Southeast by 2020. This later group includes two units being built by Southern Co. and its partners at the Vogtle plant in Georgia, as well as two new units being built by SCANA and Santee Cooper at the V.C. Summer nuclear plant in South Carolina, he said.
While those are all indicators of good news for nuclear power, Barber said “downs” for the industry include issues with the San Onofre plant in the West and the Crystal River plant in the Southeast, which ended up in retirement. The Kewaunee plant in Wisconsin was retired for economic reasons. Overall, nuclear plants are having a tough time in this era of cheap natural gas, he said. Also nuclear units are “having a hard time competing with the subsidized wind generation at night.”
Cassell noted that one broad trend involving combined cycle plants is that “in a lot of places, simple cycle is making something of a return and … in some areas, they’re even going for smaller, reciprocating engine projects because those are highly flexible, even more so than simple cycle gas turbine” projects.
He added that there is a sort of “interesting cross-drift between that trend toward the larger combined cycle plants – and there are a number of them, like [a] 3,400 MW plant … in Texas – but there’s also another counter-trend toward smaller things, simple-cycle turbine, reciprocating engine-type plants.”
Knutson discussed recent trends involving the U.S. electric utility fuel mix. As noted in his presentation, during the most recent 12 months ending last August, coal represented 35% of the country’s electric fuel mix, gas represented 31%, nuclear represented 20%, hydro represented 6%, other renewable sources represented 7%, and oil represented 1%.
Also, in the most recent 12 months ending last August, compared with the same period last year, for electric utilities, the average delivered price to U.S. electric power plants was as such:
•Coal was down 2.5% to $2.32/mmBtu
•Gas was down 22.5% to $3.97
For independent power producers, the figures were:
•Coal was down 3.1% to $2.17/mmBtu
•Gas was down 31.6% to $3.42
Electric rates during that time period for residential customers were up 1.9% to 12.6 cents per kWh, and up 1.0% to 10.4 cents per kWh for all other customers.
Electric sales, for the most recent 12 months ending last August, compared with the same period last year, were down 0.2% for residential; up 0.7% for commercial; and down 0.6% for industrial. All sales were up 0.02%, or essentially flat, the presentation added.