Utility leaders often say they can meet whatever policy obligations states impose — if the policies are clear. New Energy Department numbers show that's largely the case — at least for now
Data compiled from utility compliance filings show they are incorporating the renewable energy capacity into their generation portfolios as required of them by interim state mandate targets, according to a new report from Lawrence Berkeley National Laboratory (LBNL) summarizing progress across the nation.
The report also suggests utilities are on track to meet the renewable portfolio standard (RPS) obligations ahead – if compliance costs don’t derail the programs.
“RPS achievement averaged 95% in 2014 and 94% in 2013,” according to the U.S. Renewables Portfolio Standards 2016 Annual Status Report. The data covers the period from 2000 to 2015 and highlights recent trends.
“RPS policies aim at a final target but there are interim targets along the way as the obligation ramps up,” explained LBNL Research Scientist and report lead author Galen Barbose. “In general, utilities have been achieving the interim targets consistently.”
The RPS scene in 2016
An RPS is, according to LBNL, a requirement of retail electric suppliers to use renewables deemed eligible by the state to supply “a minimum percentage or amount of their retail load.” Electricity suppliers, mostly regulated utilities, usually face a penalty for failing to comply.
Compliance is often demonstrated by, and may be facilitated by, tradeable renewable energy certificates (RECs).
The RPS policies in 29 states and the District of Columbia (DC), no two of which are the same, apply to 55% of U.S. electricity sales, LBNL reports.
Early RPS programs in states like Iowa and Texas were established by largely bi-partisan legislation to take advantage of state resources. In recent years, as the politics of renewable energy has become more polarized, the count of state policies has remained static, Barbose noted.
“In 2015, Kansas repealed its RPS and Vermont adopted the first new RPS since 2009,” he added. “What we are seeing, however, is a critical mass of states passing legislation increasing their existing targets.”
Significant recent actions, besides the Vermont RPS, include legislation moving California up to 50% renewables by 2030, moving Hawaii up to 100% by 2045, and moving Oregon to 50% by 2040, LBNL reports. A gubernatorial directive also moved New York to 50% renewables by 2030.
“And the Maryland legislature just increased the state RPS from 20% by 2022 to 25% by 2020,” Barbose added.
National Association of Regulatory Utility Commissioners (NARUC) President Travis Kavulla is among those who has concerns about RPS expansions.
“It is up to each state to decide the kind of energy policy it wants,” he told Utility Dive. “In traditional least cost planning, the utility decided what it wanted and went after the least cost per kWh of energy. Now we have overlapping public policy goals.”
NARUC’s only official position is that resource planning should be done efficiently and, as much as possible by state utility commissions, he added. “A renewable standard is only good or bad depending on whether it achieves its goals.”
What RPS policies have done
RPS policies are not the only source of U.S. renewables growth, but they have historically been one of the major drivers, Barbose said.
Of the 100 GW of non-hydro renewables capacity added to U.S. generation since 2000, LBNL reports, 60% of renewable electricity generation and 57% of renewables capacity has been “contracted to load serving entities with active RPS obligations or is otherwise sold into RPS markets.”
More recently, “other drivers have become more significant,” LBNL reports. Price competitive wind in Texas and the Midwest, net metered solar in California, and utility-scale solar in the Southwest are now being procured outside mandate requirements. The role of RPSs has declined “from 71% of annual renewables builds in 2013 to 46% in 2015," according to the report.
Newer drivers now having an impact on renewables growth include the Clean Power Plan and corporate procurement, Barbose said.
The low greenhouse gas emissions and long term fixed price of a 20- to 30-year power purchase agreement for utility-scale wind or solar offer hedges against both the price volatility of natural gas and the potential costs of coming environmental regulations, he added.
But if the goal is to deal with carbon dioxide emissions, NARUC's Kavulla said, “renewable standards are an inefficient way to do it.”
A carbon tax or fee, though less politically feasible, is more efficient, he said. “Most economists would say that if carbon is the issue, have a policy that is for abating carbon dioxide. We need to ask what renewable standards are aiming at.”
The vast majority of utilities, wary of non-compliance consequences, have met their interim guidelines under state RPS standards, LBNL found. Only utilities in the Northeast have failed to consistently meet RPS targets, the paper reports.
“Those states tend to be under 100% [compliance] because of challenges of supply keeping up with demand,” Barbose said. “It has been more difficult to build new generation because there is less available space and a higher population density.”
RPS policies in the Northeast are often also designed differently, he added.
In the Northeast’s restructured electricity markets, utilities and other electricity suppliers can and do meet mandate obligations by making one year or short term purchases of RECs instead of buying or contracting for new generation.
Without long-term contracts, it is difficult for developers to get financing. With less capacity being built, the supply of renewables falls short of demand.
New state policies are being introduced to resolve this impasse, Barbose said. Policymakers are imposing requirements on the region’s regulated utilities to contract from developers.
"The regulated utilities continue to serve a large fraction of the load,” he said. “There have been procurements, contracts have been signed, and projects are going into construction, but it is too soon tor verdict on whether the fixes are working.”
There are two other states falling short, LBNL adds. The Illinois Alternative Compliance Payment has been too low to support growth. And regulators have excused Public Service Company of New Mexico (PNM) from procurements because it has met the state’s low cap on costs.
RPS policies continue to drive growth
The demand for renewable energy that will come from RPS policies over the next fifteen years is “substantial,” LBNL reports. The targets for 2015 created a demand of 215 TWh which rises to 431 TWh in 2030. About 40% of the growth will come from California’s new 50% mandate, LBNL adds.
One of the more surprising things in the data is that a lot of capacity is needed, Barbose said. “It was almost conventional wisdom that states have more or less fulfilled their requirements. In some specific states, that’s true. But for the U.S. as a whole there is quite a bit of growth still needed.”
Current non-hydro renewable generation aggregate demand is equal to about 8% of total retail electricity sales and current RPS requirements are about 4.8% of retail electricity sales, LBNL reports.
The RPS requirements will grow to about 9.3% of total retail electricity sales in 2030, LBNL calculates. If supply were to grow by the same amount, it would be about 12.1% of electricity sales in 2030.
“That is not a projection of renewable energy growth,” Barbose said. “There are and will continue to be other sources of renewables demand. It is only a benchmark of what renewables supply would grow to if it follows the same growth trajectory as RPS demand.”
Existing RPS demand will require 22 GW of new renewables capacity by 2020 and 60 GW of new renewables capacity by 2030, LBNL reports. That is “roughly a doubling of total RPS-builds to-date…[and] more than a 50% increase from current non-hydro renewables capacity.”
“Put simply,” Barbose said, “we are halfway to meeting all the existing RPS standards, in aggregate.”
The 6 GW of new renewable capacity added in 2015 keeps the build rate “on pace to meet residual needs,” LBNL also reports.
Much of the near-term demand is likely to be met with the 28 GW of renewables capacity already under development, LBNL adds.
Carve-outs prove problematic
There are carve-outs are in DC and 18 states specifying that a specific portion of new renewables must come from solar or distributed generation (DG). Some carve-outs multiply the credit for building solar or DG. Another 3 states have only multipliers.
Utilities are not doing quite as well at meeting carve-outs, LBNL’s numbers show. But carve-outs are not all the same, Barbose said. “Solar carve-outs are not restricted to distributed solar and DG carve-outs are, but they may include other DG resources.”
Though this makes data analysis of carve-out compliance somewhat more ambiguous, “DG tends to be mostly distributed solar so, for the report, they were lumped together,” Barbose said.
Some states have fulfilled or over-subscribed carve-outs. Among them are New York, North Carolina, and New Hampshire. But there was still 4 GW of demand from carve-outs in 2015 and that is expected to grow to 8 GW in 2020 and 11 GW of demand in 2030.
Despite the over-supplied states, carve-outs will require 2 GW of new solar/DG capacity in 2020 and 5 GW in 2030, led by Massachusetts, Maryland, Minnesota, and New Jersey, LBNL reports.
“We have already built about 5 GW for solar/DG carve-outs so, again, we are about halfway there,” Barbose said.
Rising compliance costs
A previous LBNL study estimated the value of benefits from greenhouse gas reductions and air pollution reductions obtained from renewables built to meet RPS obligations totaled about $7.4 billion in 2013.
It would be reasonable to assume the substantially increased cumulative renewables capacities in 2014 and 2015 provided even more benefit, Barbose said.
This new data shows the cost of compliance went from $11/MWh and $2.1 billion in 2013 to $12/MWh and $2.6 billion in 2014.
Reasons for the year-over-year cost increase include the building of more capacity, a partial shift to higher-cost distributed generation, and higher REC prices in some states, LBNL reports.
The cost of RPS compliance was 0.8% of the average retail electricity bill in 2012, 1.0% in 2013, and 1.3% of the bill in 2014. Even with the $0.5 billion total increase, it was a very small portion of an electricity customer’s bill, Barbose noted.
The numbers are, however, large year-over-year percentage increases, he acknowledged.
“Utilities will be interested in the bill impact because costs are one of the more politically-charged aspects of the RPS,” Barbose said.
Only two legislative efforts to roll back RPS standards have succeeded but there have been many recent efforts and they are frequently based on claims that the RPS drives up rates and has a big impact on customer electricity bills, he added.
“If you assume the 1.0% to 1.3% increase continues linearly for 15 years, you could get to bigger number,” he said. But there are three reasons that isn’t likely, he believes.
First, the recent cost increases came from higher interim targets and many states will hit their peak in the next few years, causing the impact to plateau.
Second, rate impact increases “will be mitigated by renewables continuing to get cheaper while the generation they compete against do not,” he said.
Third, most RPS policies have safety values such as cost caps so that even though costs have risen over time, the increase cannot go on indefinitely, Barbose said.
Different states use different cost containment mechanisms, but typically limit cost increases to 1% to 4% of the retail electricity bill, LBNL reports. Mechanisms include alternative compliance payments that impose REC price caps, rate impact or revenue requirement caps, caps on RPS surcharges, caps contract prices, caps on state renewables funds, or financial penalties.
There are two takeaways from this, Barbose said. The first is that these safety valves will limit cost growth. But the second is that some states may start bumping up against the cost caps as the volume of procurement rises.
That could limit renewable development, as happened when New Mexico regulators excused PNM from further procurement, he said.
And that could lead to the politically-charged question of whether to increase the cap and increase the cost of electricity, he acknowledged. “In many cases, the cost cap is part of the enabling legislation so it would take new legislation to change the cap.”
Lawmakers seeking to increase the cap might then face the political calculation of whether to “open up Pandora’s Box and risk the RPS being repealed,” Barbose noted.
Kavulla is concerned about the coming costs of RPS policies.
“Once renewable penetrations get to 40% and higher on the electric grid, those last blocks of renewables tend to be quite expensive to integrate,” he said.
Even a declining cost of renewables' installed costs may not abate the costs of new grid capacity and new backup resources, he added. “The antidote to this is to allow utilities to use least cost planning.”
A renewables standard dictates that even if the cost outweighs the benefits, the utility is required to add it to the generation mix, Kavulla said. “With least cost planning and it was the least cost option, you wouldn’t need a mandate to do it.”
Historically, the most new capacity has come from wind, but solar procurement is increasing, LBNL reports.
There are three reasons for this shift, Barbose said. First, wind-rich Plains and Midwestern states, and especially Texas, have achieved their targets. They continue to build cost-competitive wind but it is outside RPS requirements.
Second, solar-rich states, especially in the Southwest, have RPSs and are commonly still in pursuit of their targets.
Third, procurement is beginning to reflect the trend toward distributed generation and especially toward distributed solar.
None of these answer Kavulla's main question about RPSs.
“Renewables standards don’t decarbonize the system in an economically efficient manner,” he said. “It is the prerogative of the legislative branch to decide what kind of interventions into utilities and utility commissions’ least cost planning are necessary. But what are they trying to get at?”
The mandates do not seem to answer basic questions, he insisted. “Do legislators think renewables in and of themselves are good? Or are they trying to decarbonize? Or are they trying to promote local economic development or jobs? Unfortunately they have a tendency to do things that are popular even though the underlying goals are somewhat ambiguous.”
The future role of RPS policies, according to LBNL, depends on factors particular to the policies themselves and factors affecting renewable generation more broadly.
RPS standards will face the challenge of managing compliance costs and negotiating the cost cap conundrum. They will continue to face legislative and legal challenges. And, as they are fulfilled, they will face the political controversy of whether they should be extended. These questions will require advocates to respond to changing market and policy conditions.
More generally, questions like Kavulla's about the necessity of RPS policies will likely come up in debates about the Clean Power Plan and other environmental regulations. And, LBNL concludes, as penetrations increase, controversy will increase over the siting, grid integration, and rate structures for renewables.