The Vogtle nuclear power plant cost is projected to balloon to more than $12,000 per megawatt. In a study we did for the California Energy Commission in 2009, even at $4,000 per megawatt, nuclear power was uneconomic. This explains why nuclear power is not taken seriously as a solution to reducing greenhouse gas emissions.
GTM compiles the studies done over the last month in anticipation of the release of the study ordered by Energy Secretary Rick Perry to examine how increased renewable energy threatens grid reliability.
California passed AB 57 in 2002 to make the power procurement process for electric utilities confidential (as well as subject only to upfront review rather than ongoing prudence standards). The result has been overly high prices locked in for decades. A new study on the relative gains to landowners who sell the development rights for oil and gas development in Texas shows that using auctions creates more competition among multiple bidders than bilateral negotiations. As a result, landowners get higher prices for their development rights through an auction. The corollary is that California’s electric utilities probably could lower their power purchase costs by moving to public auctions instead. Yet another reason to repeal AB 57.
I’ve been struck by the lack of panic in the energy industry about President Trump’s decision. This article goes into that underlying confidence that the momentum appears unstoppable.
WASHINGTON — President Trump’s decision to abandon the Paris Accord will slow the battle against climate change in the U.S., but there’s too much momentum in the nation’s clean-energy economy to shut it down, energy experts say.
California’s investor-owned utilities (IOUs) have asserted that the underlying costs molding time variant or time of use (TOU) rate structures should be largely, or even exclusively, derived based on conventional fossil generation costs. The IOUs rely on “net load” to determine TOU prices, calculated by subtracting all load met by renewables, nuclear and hydropower generation—the majority of the utilities’ generation fleets.
In theory, net load is the portion of the load served by fossil-fueled generation that has the highest short-run operating costs, and therefore is “marginal.” The infamous “duck curve” shown above depicts the net load (not the metered load.) Yet, the marginal energy generation for most load is no longer served by natural gas; it is now met by renewable energy contracts. The utilities’ net load approach ignores the bulk of their true marginal costs to serve added load, which arise from procuring renewables. The IOUs’ resource procurement has been dominated by adding solar, wind, biofuels, and other renewables since at least 2006 to meet the state’s renewable portfolio standard (RPS), first at 20 percent, then 33 percent, and soon 50 percent.
The tunnel-vision focus on net, rather than the entire, load is especially problematic in the context of State policy to phase-down fossil fuel generation. Eventually, natural gas production will even more significantly diminish, and could disappear from the grid entirely, leaving no price-setting metric under this paradigm. Insistence on the net load approach in the face of this transformation is akin to evaluating the economics of ridesharing based on the exclusive cost of taxis, without consideration of Uber® and Lyft®.
Once fossil-fuel resources are used minimally – an explicit state goal reflected in SB 350 – and potentially no longer on the margin, it is unclear what price benchmark the utilities will propose to set time-variant rates. Continuing the trend toward fewer fossil-fuel resources is already reflected in pending legislation in Sacramento that proposes a clean-peak standard – AB 1405 – and a 100 percent Renewable Portfolio Standard—SB 584. Relying solely on the cost of generation resources that State policy plans to phaseout to define TOU periods is inconsistent with good, long-term, ratemaking principles. Instead, marginal energy generation costs should be calculated, at least in part, from a set of recent RPS-eligible PPAs, weighted by time of delivery.
Likewise, the marginal energy costs derived using the net load method, which drive the proposed shifts in TOU periods, reflect less than one-third of total average utility rates. The IOUs do not explain why cost differences within a modest component of overall rates should steer determination of TOU periods.
Further, it is not clear why the California Public Utilities Commission (CPUC) should rely on a speculative forecast about load shapes in 2024—seven years from now—to set today’s TOU periods. As the CPUC is well aware, the electricity system is changing rapidly along many dimensions. Infusion of utility-scale renewables, which is driving the IOUs’ rate analyses, is but one factor. Increasing amounts of storage and electric vehicles, shifting work patterns, and other social and economic factors will substantially influence load profiles over the next decade. In 2006, few energy experts foresaw stagnant, or even falling, electricity demand; there is even greater uncertainty today.
This perspective excludes contributions made by utility-scale renewables that meet most of the remaining load, and by customer-side resources.