Grants totaling $200,000 each will go to the nine-county San Francisco Bay region; Central Coast cities in Ventura, Santa Barbara and San Luis Obispo Counties; and the San Diego and Sacramento regions. The combined area is home to nearly 14 million people, who are expected to be strong early adopters of EVs, the agency said in a series of press releases.

Currently, there can be long wait times for inspectors to approve residential home chargers, and there is a lack of coordinated planning for complex installations at commercial properties, government facilities and multi-unit dwelling complexes, the agency said.

The grants will bring together public and private leaders from counties, cities, public agencies, community organizations, private industry, higher education, and utilities to create best-management practices to overcome these and other obstacles. They will be tasked with determining the best placement for charging stations, creating consistent permitting and inspection guidelines for EV chargers and ensuring that any infrastructure improvements to facilitate EVs do not cause supply problems for the local electric grid, among other goals, the agency said.

The California Air Resources Board recently unanimously approved regulations that require car manufacturers to cut smog emissions from new vehicles by 75 percent by 2025 and reduce greenhouse gases by 34 percent. To meet these goals, the number of plug-in battery electric vehicles in California is expected to double from current levels by 2013 and reach 460,000 by 2020.

A 2007 state law authorized the California Energy Commission to develop and deploy alternative and renewable fuels and advanced transportation technologies that run on electricity, hydrogen, natural gas and biofuels to help achieve the state’s climate change policies. California currently has the largest network of EV charging systems and hydrogen fueling stations in the country, according to the Commission’s 2011 Integrated Energy Policy Report.

Resources:

From Yale Environment 360: Interview with California Energy Commission Chair Mary Nichols – “California’s ‘Clean Car’ Rules Help Remake U.S. Auto Industry”

A law enacted last year directed NYSERDA to conduct the study, which assesses the costs and benefits of installing 5,000 megawatts (MW) of PV in the state by 2025, compared with its current capacity of 19 MW.

That goal could cost anywhere from $1.4 million to $4.3 million per installed MW, depending on a range of factors, including the availability of federal tax credits and the cost of photovoltaic panels, which have slid by 40 percent in the last year alone, according to industry sources.

Costs are falling so fast, due to a variety of global forces and increased efficiencies, that solar could conceivably compete with regular grid power without any need for subsidies within the next five years, several industry sources said during a hearing in Harrisburg, Pennsylvania last month on a bill to bolster that state’s solar market.

If achieved, New York’s 5,000 MW goal would lead to a four percent drop in fossil fuel consumption production in the state and a three percent decline in carbon dioxide emissions, and create 2,300 jobs directly related to solar installation. But the overall impact to the economy would be negative, largely because of the cost to ratepayers – which would range anywhere from $300 million to $9 billion, depending on different modeling scenarios, the study says.

“Nevertheless, even with this range of cost uncertainty, given the many potential benefits that PV has to offer and the long-term potential for lower-cost PV technology, New York State should support continued investment in the steady and measured growth and deployment of PV as part of a sound and balanced renewable energy policy,” the report says.

New York’s current installed solar PV capacity of 19 MW places it well behind other states in the region, according to the National Renewable Energy Laboratory’s online ranking of state PV installations. New Jersey, for example, is home to 186 MW, the second-highest capacity after California, followed by Pennsylvania with 58 MW, Massachusetts with 35 MW, and Delaware and Connecticut each with roughly 26 MW.

The NYSERDA study reviewed a range of policy options being employed in the U.S. and abroad to spur investment in solar power. The magnitude of the cost uncertainties associated with implementing the 5,000 MW goal “suggests the need for a policy response and investment strategy that is both flexible and responsive,” the report says.

Recommendations include continued development of policies such as net metering, sales tax exemptions and interconnection standards that could reduce the cost of PV installation. The study also calls for more streamlined permitting processes, and continued financial support for targeted research and development, workforce training and business development, which could help lower installation costs.

Solar proponents also note that once solar is installed, it can actually lower overall electricity prices for customers and reduce costs for utilities by relieving grid congestion. For example, a solar PV installation near Allentown, Pennsylvania will save a school district there $3.8 million in electricity costs over 20 years, said an industry source testifying at the hearing in Harrisburg last month. In addition, the solar panels will send any excess electricity back into the grid, relieving demand bottlenecks and enabling the utility to avoid making costly upgrades on currently stressed distribution lines, he said.

In New Jersey, several county governments have implemented financing models for solar that are reducing costs by up to two thirds over 15 years.

Pennsylvania’s fast-growing solar industry could face massive layoffs if state policymakers fail to take immediate steps to bolster the market for solar credits, industry sources told a hearing of the House Consumer Affairs Committee in Harrisburg on January 11.

Solar Renewable Energy Credits (SRECs) serve as a critical source of financing for solar projects, but prices have plummeted over the last year due to oversupply.

At stake are more than 1,000 solar industry jobs and hundreds of businesses, which have flocked to Pennsylvania during the last three years to take advantage of its solar energy mandate and generous state and federal incentives, said Pennsylvania House Urban Affairs Committee Chair Rep. Chris Ross, who has sponsored legislation to bolster the market.

“The bill would allow for a reset of the marketplace,” said Rep. Ross, who also chairs the CSG/ERC Energy & Environment Committee. “If you want to continue to see solar operations here in Pennsylvania, we need to make an intervention at this point to save those jobs,” he said.

Pennsylvania’s 2004 Alternative Energy Portfolio Standards Act (AEPS) requires retail electricity suppliers to purchase gradually increasing amounts of alternative energy as part of their overall portfolios, including 0.5% from solar photovoltaic sources by 2021. They can fulfill that requirement by buying SRECs produced by solar systems owned by residents or businesses, with each SREC equal to one megawatt-hour of generation. Suppliers who fail to meet the state’s solar mandate must pay a fee known as an Alternative Compliance Payment (ACP).

Among other provisions, Rep. Ross’s bill would accelerate electricity suppliers’ SREC requirements between 2013 and 2015 by 4.5%, but leave the overall goal of 0.5% by 2021 unchanged.

Solar industry sources said that a combination of forces had caused the number of new installations in the state to soar but now threatened to send the industry over a cliff.

The market exploded starting in 2008, when the administration of former Gov. Ed Rendell set aside $180 million in grants, rebates and loans to support residential, small business and commercial solar projects. An additional $11 million was added from federal stimulus grants and other funding sources.

That money, coupled with a 30% federal investment tax credit, generated a flood of interest among businesses and homeowners in solar, and has led to the completion of more than 5,000 projects since 2009. Solar capacity in the state currently totals more than 100 MW, more than double the current AEPS requirement. In fact, there is already sufficient capacity built and planned to meet the requirements through 2015, according to a status report released last August from the state Public Utilities Commission.

With the bulk of the grants and rebates dried up, and a glut of credits, there is little demand for the market to grow. SREC prices have plunged from an average of around $300 to as low as $20 today, said industry sources. A provision in the AEPS legislation that allows out-of-state SRECs to be sold to in-state utilities has further depressed the market. Pennsylvania is the only Northeastern state that allows the practice; markets in Maryland, Delaware, New Jersey and New York are all closed to SRECs from other states.

Representatives of electric and natural gas distribution companies testified against the bill, calling the in-state requirement protectionism, and warning that it could violate the Commerce Clause of the U.S. Constitution.

The measure could cost ratepayers up to $2.3 billion between now and 2021, said Terry Fitzpatrick, president of the Energy Association of Pennsylvania. “We’re removing the investment risk from the solar industry investor and we’re placing it on the consumer,” he said.

Solar industry sources disputed the cost estimates produced by utilities as wildly elevated. The Pennsylvania Solar Energy Industries Association estimates the bill would increase ratepayer electricity bills by around $2.50 per year.

A source from Solar City, a national solar provider, said forecasts for dire rate hikes did not factor in expected increases in regular grid power going forward, or take into account declining solar installation costs, which have dropped by 40 percent in the last year alone. A solar panel that would cost $325 in 2008 costs less than $100 now, said the source.

Others argued that solar installations can actually lower overall electricity prices for customers and reduce costs for utilities by relieving grid congestion. For example, a solar photovoltaic installation near Allentown will save a school district there $3.8 million in electricity costs over 20 years, said Dean Musser, President of Tangent Energy Solutions, based in Kennett Square. In addition, the solar panels will send any excess electricity back into the grid, relieving demand bottlenecks and enabling the utility to avoid making costly upgrades on currently stressed distribution lines, he said.

In New Jersey, several county governments have implemented financing models for solar that are reducing costs by up to two thirds over 15 years.

But those who oppose efforts to aid Pennsylvania’s solar industry – the majority from fossil-fuel-generating companies – insisted that consumers would be better off by letting the fate of the solar industry play out at the hands of market forces.

“We believe that we need to give a market pull and not a government push or else we’re going to have skewed results like we see here today,” said Jacob G. Smeltz, Vice President of the Pennsylvania Electric Power Generation Association. “HB 1580 is an attempt to intervene in the law of supply and demand.”

But Rep. Ross said that it was precisely the decision by government in 2008 to flood the marketplace with grants and rebates that produced the imbalance threatening its viability today.

“We, the government, did change this marketplace,” said Rep. Ross.  “I think we have to take responsibility for that, so that those who entered the marketplace in good faith won’t have to suffer as a result.”

Representative Ross is preparing amendments to reinforce his primary goal of correcting the market and not increasing costs for suppliers who would need to comply with the new requirements.

The amendment would offset the near-term 4.5% increase in the SREC requirement with a corresponding decrease in later years; establish a cap on SREC prices by placing a ceiling on the ACP that will decline over time; and allowing for solar thermal technology to qualify for SRECs.

“We want to send a clear signal that we are not trying to favor the solar industry, and that we want to correct a problem that we created,” he said.

– By Rona Cohen

Already a leader in energy efficiency and renewable electricity, Vermont aims to leverage innovative financing mechanisms, technologies, regulatory policies, and public-education efforts to expand its clean-energy economy, keeping dollars from flowing out of state and freeing residents from the volatility of fossil-fuel prices, according to the plan.

The CEP crowned a year of hard work by multiple state agencies in conjunction with regional planning commissions, town energy committees, business leaders, non-profit groups, and the public-at-large who submitted over 9,000 comments for consideration.

“I am proud of the incredible work put in by the many agencies involved and the thousands of citizens who took the time to participate in shaping the ideas and actions that are included,” said Gov. Peter Shumlin in a press release.

“Vermont needs to move forward to protect our environment, gain greater energy independence, and drive innovation and jobs in the energy sectors,” he said. Shumlin praised the CEP for putting the state on that path.

While acknowledging Vermont’s success to date in reducing demand for electricity and increasing the amount of renewable energy fed into the grid, the plan concentrates on strengthening weak areas in current efforts. Most importantly, it notes that the state will fall short of meeting previously set goals to reduce greenhouse-gas emissions by 25 percent in 2012 and 50 percent in 2028, relative to a 1990 baseline. In order to close the gap, the CEP recommends an expanded focus from electricity generation to the development of an “all fuels” or “total energy standard.”

Within the proposed broader scope, Vermont must tackle its heavy reliance on imported oil and diesel for heating and transportation, sectors that account for two-thirds of the state’s total energy consumption. Transportation alone generates 47 percent of its greenhouse-gas emissions and accounts for $1 billion worth of expenditures, dollars that mainly leave the state. An additional $600 million go toward imported heating fuel. Limitations of current programs, infrastructure and policy measures all contribute to the lack of progress in these areas, the CEP says.

Despite success in lowering residents’ heating and electricity costs, Vermont’s efficiency programs have only improved the energy performance of about 6,700 houses since 2008. The CEP calls for an aggressive push to raise that number to 8,200 annually, so that the state legislature’s mandate of retrofitting and weatherizing 82,000 residences by 2020 is met.

Fuel change is also a central part of the CEP. The report recommends adding incentives to displace the fossil fuels currently used for heating with local biomass, and further proposes a significant expansion of infrastructure for transmitting and distributing natural gas, which now only fills five percent of Vermont’s energy needs. Because gas is the cleanest-burning fossil fuel with the lowest carbon footprint, and increasingly comes from domestic supplies, the CEP advocates a push to increase its availability for use in space heating and heavy transportation, and to fill in gaps in the electricity supply.

But still more is needed to reach the target of 90 percent by 2050. Transportation that relies on fossil fuel must be replaced wherever possible by plug-in electric vehicles, powered by batteries charged with renewably generated electricity, says the plan. To orchestrate this sweeping change, it recommends setting up a task force to address the complex network of elements – technological, financial, regulatory and attitudinal – that must be in place for such a transformation to be successfully made.

Construction, too, must be revolutionized.  As a first step, the CEP recommends an increase in the quantity of new homes that meet U.S. EPA’s ENERGY STAR specifications, from the current 33 percent to 60 percent by 2020. Then, further steps must be in place to move new construction beyond these standards into the cutting-edge territory of zero net energy buildings that are not only maximally efficient, but also cover their own energy needs through onsite distributed generation from renewable solar, wind and geothermal resources.

The plan recognizes that innovative policies and regulations will be an integral part of meeting these ambitious goals. To leverage energy improvement, it advocates exploring more sources of potential funding such as utility on-bill financing or dedication of some of Vermont’s Qualified Energy Conservation Bond allocation to that purpose. It also suggests building on lessons learned from the state’s current Sustainably Priced Energy Enterprise Development program (SPEED) in order to create better Standard-Offer contracts for small-scale renewable distributed generation, and recommends the adoption of a mandatory Renewable Portfolio Standard for electricity, tailored specially for Vermont but in line with other New England states.

The CEP even addresses the opportunities that can be found in adversity – in this case, the destruction left last August in the wake of Tropical Storm Irene. The likelihood of future increases in severe weather events makes it critical to align local, regional, and state policies so that rebuilding and growth add greater resiliency to the infrastructure of Vermont’s towns and villages, and contribute to reduced carbon emissions, says the plan. Prior to Irene, Vermont had set a goal of a five-percent reduction in energy usage across state government. Given the current need for significant infrastructure repair and rebuilding, the plan recommends that the state use the occasion to make government buildings more efficient, while strategically deploying renewable-energy systems.

True to the plan’s title, the new recommendations are comprehensive and offer a challenging set of goals for the state to consider. The authors suffuse these challenges with a spirit of optimism about what Vermont can achieve, based on past experience. They stress that the state’s steps toward greater energy efficiency so far have resulted in five dollars of economic growth for every one dollar of investment plus the equivalent of 43 full-time jobs, on average, for every one million dollars its programs disbursed annually. And despite Vermont’s small size, the authors believe that in doing its part to address climate change, the state would set a powerful example and in their words, “show how environmental choices can lead to economic prosperity.”

– By Eleanor Saunders

The mechanism, frequently called the Morris Model, combines many of the benefits of the two types of financing options that local government agencies have typically used to deploy solar power: self-ownership and third-party power purchase agreements (PPA).

The result is a bond-PPA hybrid model, in which a public entity issues a government bond at a low interest rate and transfers that low-cost capital to a developer in exchange for a lower PPA price. The mechanism can provide additional benefits compared to both the self-ownership and third-party PPA models, the report says.

For example, like self-ownership, the hybrid model allows the administrator to take advantage of low-cost public debt. And as with a third-party PPA, the model enables the tax-exempt administrator to benefit through savings passed on from federal tax incentives. In addition, the administrator receives fixed electricity costs for a long-term contract and has no operating and maintenance responsibilities for the solar PV equipment.

To date, the model has been used to finance solar PV projects on schools, colleges, county administrative buildings, and other public buildings in four counties in New Jersey, and some of those projects are lowering electricity costs by two-thirds. Seven other counties in the state are in the process of adapting the model.

The report says the model could be replicable in other states, though the existence of certain laws and regulations could impact its implementation.

Resources:

NREL Fact Sheet: Financing Solar PV at Government Sites with PPAs and Public Debt

CSG/ERC Webinar on Public-Sector Financing Options for Solar Power (February 25, 2011)

In addition to improving access to funding for energy improvements, especially for multifamily buildings and small businesses, on-bill programs offer the potential for traditionally credit-constrained customers to gain access to financing through modified underwriting that takes bill payment history into account, said ACEEE in a press release.

In the residential market, a handful of on-bill pilot programs are being tested and refined across the country, in states including Kentucky, Kansas and Oregon, with the hopes of surmounting some of the well-known but formidable barriers that have stymied the market for home retrofits in the past. They include challenges such as high upfront costs, a complex application process and uncertainty over future energy savings.

Earlier this year, New York Gov. Andrew Cuomo signed legislation that will create the first-in-the-nation statewide on-bill repayment program.  The law compels the seven utilities operating in New York to provide on-bill repayment for loans for energy efficiency retrofits offered by NYSERDA through the Green Jobs-Green New York program for residential homeowners, multifamily buildings, small businesses and not-for-profit organizations.

For additional information, see:

ACEEE report: On-Bill Financing for Energy Efficiency Improvements: A Review of Current Program Challenges, Opportunities, and Best Practices

NYSERDA Green Jobs-Green New York Annual Report, July 31, 2011

State and Local Energy Report: Broadening the Reach of Home Efficiency through On-Bill Programs

Proponents of offshore wind development say the clean power source could transform the energy economy of the Atlantic Seaboard, although formidable cost and regulatory barriers continue to hamper progress here.

At an industry conference sponsored by the American Wind Energy Association (AWEA) on October 11 to13 in Baltimore, developers were cautiously optimistic that a string of utility-scale wind farms will eventually take shape in U.S. waters and send clean power to high-population centers up and down the Eastern Seaboard. But success, they say, hinges on having the types of consistent policies that have made the sector surge in Europe, and increasingly, in China.

In a series of panel discussions, developers noted that in countries like the United Kingdom, Denmark and Germany, certainty about the permitting process, a predictable revenue stream and grid connections that can serve large-scale wind farms have enabled them to attract capital at rates favorable enough to finance a fast-expanding number of offshore projects.

As a result, more than 3 gigawatts (GW) of installed offshore wind capacity already generate power from sites in European waters spanning nine countries, and an additional 150 GW are in various stages of planning, according to the European Wind Energy Association.

In contrast, the U.S. has yet to see a single turbine erected offshore, though the federal government has set a goal of harnessing 54 GW of wind power along the U.S. coastlines, in the Gulf of Mexico and Great Lakes by 2030.

What developers do not question is the strength of the resource here. A report last year from the U.S. Department of Energy’s National Renewable Energy Laboratory estimates that overall, this country has the potential to produce more than 4,000 GW of power from offshore wind, four times the nation’s total electric generating capacity from all sources, based on 2008 figures.

“We need two key things for this industry to take off: submerged land leases, and secure offtake,” such as long-term power purchase agreements (PPAs), which are critical if developers are to obtain financing for a project, said Tim Ryan, senior vice president of APEX Wind Energy, based in Charlottesville, Virginia. “At this point, we don’t really have either of those,” he said, during a panel discussion with other developers.

In a PPA, power producers and utilities agree to purchase or sell power at fixed prices over a specific term that can extend up to 25 years. Electricity generators whose plants use coal or natural gas are often reluctant to enter into such agreements, given that fossil-fuel prices tend to be volatile and can fluctuate considerably over time. But since the wind is free and operating costs are fairly fixed, wind power producers can offer long-term fixed-price contracts without fear of broad price fluctuations.

The agreements, with their guaranteed payments over a set number of years, enable developers to obtain critical financing for a project. And proponents argue that they protect utilities and ratepayers against the volatility of fossil fuels markets that, though below the price of offshore wind today, could conceivably exceed its cost in ten to 15 years, depending on a range of global demand factors.

Yet PPAs can be a hard sell for utilities and the public. A bill in Maryland last session that would have required four large utilities to enter into a long-term PPA for power produced from a 400 MW to 600 MW ocean-based wind farm was unpopular among utilities, whose power procurement process is based on far shorter, two-year state contracts. The measure drew criticism from business groups as well as power companies, who argued that the cost passed on to consumers would be too high, though it would have capped the increase at $2 a month for residential customers, and 2.5% for commercial ratepayers.

The three PPAs that have been signed thus far in the U.S. – for offshore wind projects in Rhode Island, Delaware and Massachusetts – will charge comparatively high power rates, which in some cases are more than double the cost of regular grid power.

Overcoming First-Mover Cost Barriers

Offshore wind proponents say that as larger projects get built, they will create economies of scale that will bring construction and capital costs down, and in turn, reduce power rates for consumers. But that creates a conundrum for developers of the earliest pilots who are trying to garner support from the public during a challenging economy.

As first movers in a nascent industry, they must charge high electricity prices to obtain financing for projects that have yet to test the weather- and infrastructure -related challenges particular to ocean construction here. If initial pilots function as anticipated, second-generation, utility-scale offshore wind farms coming online a decade or less from now will reap the benefits of proven performance and economies of scale, and provide power at lower rates than the early projects.

An example of this price inconsistency is playing out in Rhode Island, where electricity produced by a 30 MW pilot project planned by Deepwater Wind off the coast of Block Island is expected to be considerably more costly than power from a massive, 1,000 MW wind farm proposed by the developer that could come online in the area within the next few years.

Last year, Deepwater signed a 20-year power-purchase agreement with National Grid, which will buy power from the Block Island pilot at a rate of 24.4 cents per kilowatt-hour (kWh), with increases of 3.5 percent each year.

Two local businesses sued to get the deal overturned, complaining about the steep rate, which is about two and a half times what National Grid currently pays for wholesale power. But last July, the PPA was upheld by the state Supreme Court.

Deepwater provided details about its latest project in a press release last month, estimating that power would cost “in the mid-teens” from its next-generation 1,000 MW wind farm planned in federal waters off the coast of Massachusetts and Rhode Island. The company said the first turbines could be up and running by 2016.

As an alternative to PPAs, some states are taking a close look at a process underway in New Jersey to create Offshore Wind Renewable Energy Credits (ORECs). Renewable energy credits represent the environmental attributes of clean power, with one REC equivalent to one megawatt-hour of electricity produced. Unlike the stability of long-term contracts, the price of RECs fluctuates over time, based on supply and demand.

New Jersey’s OREC program is an incentive program to support at least 1,100 MW of generation from ocean-based sources – enough electricity to power around one million homes. A bill signed by Governor Chris Christie in August 2010 requires utilities to buy ORECs for approved wind farms, or pay alternative compliance payments.  The New Jersey Board of Public Utilities is currently formulating regulations to establish the OREC program.

In exchange for this support for initial projects, New Jersey’s legislation places the burden on developers to show that a project will create a net economic benefit for the state. For proponents of offshore wind, such a requirement is critical, given that the promise of needed jobs and other economic growth, along with clean energy, are the core reasons for accepting the higher initial cost of ocean-based power.

The U.S. Department of Energy’s National Renewable Energy Lab has estimated that every megawatt of offshore wind produced in the U.S. will create more than 20 direct jobs.

Federal Support in Limbo

Ocean-based wind construction is roughly twice as expensive as putting turbines on land, and given that reality, developers say that some form of federal assistance will be crucial to moving forward larger-scale projects.

Extending the Investment Tax Credit (ITC) and the U.S. Department of Energy’s Loan Guarantee Program for offshore wind projects are the two top priorities of the Offshore Wind Development Coalition, an industry group. The federal loan guarantee program for renewable energy was dramatically scaled back under the continuing Congressional resolution passed earlier this year that kept the federal government open.

The ITC is slated to expire on December 31, 2012 for terrestrial and ocean-based wind development, a date that does not take into account the lengthy permitting process required of offshore development, the industry argues. They claim that none of the current projects in the pipeline would be able to qualify for the ITC by that date.

Last month, New Jersey Representatives Bill Pascrell and Frank LoBiondo introduced a bill in the U.S. House of Representatives that would eliminate the ITC’s 2012 deadline for offshore wind and replace it with a 30 percent tax credit for the first 3,000 MW of offshore wind development.

While the financing question looms large, federal officials are moving to streamline the leasing and permitting process, which also affects the willingness of investors to finance offshore projects. A lengthy timeline to obtain the necessary approvals creates risks for investors unsure about if, and when, a project will be built. It also exposes developers to uncertainties stemming from changes in a political administration and in material and construction costs during that period.

At least 4,000 MW of offshore development have been proposed in the U.S., with the bulk planned for federal waters, which begin three miles from shore. But so far, only one federal lease has been granted, for the Cape Wind project off the coast of Massachusetts, a 420 MW wind farm planned for Nantucket Sound. That lease was signed by Interior Secretary Ken Salazar during last year’s AWEA event, in Atlantic City, New Jersey. The announcement followed a prolonged, nine-year permitting process that was beset by fierce opposition from a range of local groups.

In a keynote address at this year’s conference, Salazar said that federal officials were working to accelerate the permitting process, and could be issuing new leases during the next few months, a number of which would be for development in the Mid-Atlantic region. At least ten applications have been submitted to develop offshore projects in the Atlantic Ocean, Gulf of Mexico and Lake Erie.

While generally upbeat about the industry’s prospects here, Salazar implied that greater support was needed from Congress, calling for an extension of the ITC and establishment of a national clean energy standard, measures that he said would create “investment certainty” and send “a signal to investors to move money off the sidelines.”

Salazar contrasted the U.S.’s failure thus far to harness its ocean resources with its status as a global leader in cultivating land-based wind. With more than 40 GW of installed capacity, the U.S. is second only to China. “We should be proud of that achievement,” said Salazar. “But we should also say to ourselves, ‘why is it that Germany, Denmark and China have moved so far ahead, and we have so much offshore capacity, but have yet to develop one megawatt?’”

Europe’s Approach to Growing Offshore Wind Farms

Jens Eckhoff, president of the German Offshore Wind Foundation, said the lackluster support for offshore wind in this country reminds him of the situation in Germany a decade ago, before the sector started to take off there. “There is an unclear market, no national energy policy, no single point of contact within the states,” and the “unsolved question of finance,” he said, during a panel discussion.

Germany and other European countries have subsidized the growth of offshore wind and other sources of clean power through feed-in-tariffs (FIT), which are set rates that utilities must pay a renewable-energy provider over a certain number of years, and usually decline over time.

Germany’s FIT for onshore wind, in place since 1991, has been credited for making the country home to the largest installed onshore wind capacity in the European Union. That success led the government to introduce a FIT for offshore wind in 2001. It currently stands at €0.13 per kWh and will rise to €0.15 kWh in 2012. Those rates are scheduled to decrease starting in 2015, though draft legislation released by the Environment Ministry in August would push the date back to 2018.

Today, the German wind industry employs more than 125,000 people, and 80 percent of the turbines produced there are destined for export, said Eckhoff.

Currently, offshore wind projects representing 4 GW are in various stages of development, and the government now aims to get 25 GW of power from the sector by 2030. Germany hopes to close its nuclear plants in the next 10 years, and is pushing for renewable alternatives like offshore wind to replace that power source.

Nevertheless, wrangling among developers for more favorable subsidies has slowed the pace of offshore development there, according to an article earlier this year in The London Guardian.

Taiwan has also instituted a FIT for offshore wind, as part of a new policy to wean the country from nuclear power in the wake of Japan’s nuclear crisis.

U.S. Views about Price Supports for Offshore Wind

While FITs have been far less popular in the United States than in Europe, a recent report from the Institute for Local Self Reliance, a nonprofit, found that FITs can yield economic advantages for ratepayers compared with other financing options. The report found that average FIT prices for solar power in Germany have been cheaper over time than average solar REC prices in New Jersey or California.

In North America, the state of Vermont and several municipalities have enacted FITs for renewables, but the Canadian province of Ontario is the only jurisdiction that has promoted a FIT for offshore wind. Nevertheless, that policy was put on hold last February, when the provincial government placed a moratorium on offshore wind development, saying that further scientific research was needed.

In South Carolina, a report issued by a legislative task force last year called for the creation of policies to provide “revenue certainty for offshore wind production,” with one suggestion being a feed-in-tariff.

Other states have vowed to push ahead with policies to promote offshore wind. Staff in Maryland Governor Martin O’Malley’s office said the governor plans to introduce a new offshore wind bill at the start of the legislative session in January. Lawmakers have formed a “summer study” group focusing on the price impacts of offshore development, among other issues.

A recent poll conducted by a coalition of environmental groups in Maryland found that 62 percent of respondents would be willing to pay $2 per month more on their electric bills if their electricity mix included offshore wind power.

During a panel discussion, staff from the governor’s office noted that the intention of the bill is to jump-start the market – not to have government-subsidized PPAs indefinitely. They added that in order to meet Maryland’s mandate of deriving 20 percent of its electricity from renewable sources by 2022, utilities will need to be able to draw on 1.5 GW to 2 GW of offshore wind.

“We must come together to create a market on a large scale,” said Governor O’Malley, in an address at the AWEA conference to an audience made up largely of industry representatives from the U.S. and Europe. “I charge the industry to find a better price and a cheaper way to finance this.”

–By Rona Cohen    

Until recently, this issue played a far less prominent role in the shale-gas debate than concerns about the possible harm to water supplies, air quality or the character of rural communities.[1] But over the last months, the contribution of shale gas wells to greenhouse-gas emissions has come to the fore.

Some new analyses suggest that shale gas may be responsible for significantly more emissions of methane over its full life-cycle than so-called conventional natural gas supplies. [2] Methane is a potent greenhouse gas that makes up 70 to 90 percent of unrefined gas and has an impact on climate that is at least twenty-five times greater than carbon dioxide’s (CO₂), when calculated over a period of 100 years.

Adding to the implications of the new studies are predictions that the portion of total U.S. gas production from shale formations will rise quickly, from about 16 percent in 2009 to about 45 percent in 2035.^[3] Thus, emissions from shale wells would correspondingly grow, an increase whose impact is magnified by methane’s powerful effect on climate.

These findings could challenge the reputation of natural gas as an environmentally preferable fossil fuel, less deleterious to the climate and human health than coal. This reputation has led many respected authorities – at the Massachusetts Institute of Technology and the Center for Strategic and International Studies, for example – to recommend using gas as a ‘bridge fuel’ until clean-energy technologies are mature enough to replace fossil fuels or remove their carbon emissions, a possibility if emergent carbon-capture-and-storage processes turn out to be economically and environmentally viable.

Disagreements over the climate impact of shale gas are particularly important to the approximately 15 states where laws and policies continue to require reduced levels of greenhouse-gas emissions.^[4]  Because about 80 percent of the gas in current U.S. supplies comes from conventional wells, and natural-gas power plants produce on average about 45 percent fewer greenhouse-gas emissions than coal-fired plants, several states have designated their emissions level as the benchmark by which to evaluate proposals for new generation. [5] Part of the lower emissions level has to do with the efficiency of natural-gas plants, part with a chemical transformation that occurs during combustion so that only CO_2, and not methane, is emitted from the plants.

With natural gas generating 23 percent of U.S. electricity compared to coal’s 43 percent, the potential for increasing its share in electricity markets is huge. Thus, a great deal is riding on the outcome of the debate about shale gas’s greenhouse-gas emissions from both economic and environmental perspectives.

Conflicting Analyses

The current emissions controversy was initially triggered by two analyses, one from U.S. Environmental Protection Agency (EPA) and the other from a team of researchers at Cornell University.

The first salvo was a quiet one. Without fanfare, EPA revised its estimate of methane emissions from shale-gas wells in a background technical support document to its November 2010 final rule for greenhouse-gas reporting by the petroleum and gas industries.  Based largely on data gathered from industry members of its Natural Gas STAR Program, EPA increased the numbers associated with intentional venting and inadvertent leakage of methane by 120 percent.

The next salvo, which came from a peer-reviewed study published in April 2011 by Cornell University researchers, stirred up far stronger reactions because it directly challenges the value of natural gas as a bridge fuel.  The study estimates that between 3.6 and 7.9 percent of the methane in shale gas escapes into the atmosphere from a combination of intentional venting and unintentional leakage over the productive life of a well, an amount that is at minimum 30 percent greater and possibly over 50 percent greater than conventional gas, according to conditions at individual well sites.  Depending upon the time frame used to calculate the impact of these emissions on climate – 100 versus 20 years — shale gas could put as much or even more greenhouse gas into the atmosphere than coal, the authors contend.

Both EPA and the Cornell researchers note that the methane emissions could be reduced through improved industry practices.  A variety of available technologies decrease vented and fugitive emissions by as much as 90 percent, and the expense of installing them would be offset relatively quickly through sales of the captured methane, according to information from partners in EPA’s Natural Gas STAR Program, a voluntary group exploring “green” industry practices.[6]

But despite the acknowledgement that a remedy exists, the response from industry and other energy experts to EPA’s revised figures and the Cornell study has been heated. The most comprehensive critique comes from IHS CERA, an energy consulting company that works with industry clients.

In their assessment, the IHS CERA authors raise three main objections to EPA’s analysis.  They contend that the agency misinterprets industry data points about methane emissions, assumes the ratio of venting versus flaring a well’s emissions prior to its production of saleable gas is higher than it actually is,[7] and mistakenly presumes that the greater productivity of shale-gas wells means that more methane emissions occur. EPA does not consider that increased productivity may imply that fewer wells are drilled, thereby reducing emissions, and it wrongly posits a venting rate far higher than safety allows and good industry practice supports, IHS CERA says.  Based on IHS CERA’s calculations, actual shale-gas methane emissions are only one-third what EPA estimates. The critique also says that Cornell study commits many of the same errors.

Most other substantive analyses, which appeared around the same time as the IHS CERA study, have entered the fray by addressing to what degree prior analyses were on target or not.[8] On balance, more of them conclude that EPA and the Cornell team overestimated emissions to at least some degree.

Only one study, published in August 2011 by a team of researchers from Carnegie Mellon University, put together its own independent data points, specific to the context of Marcellus shale gas, in an attempt to improve the accuracy of results. The study occupies the interesting position of receiving funding from the Sierra Club, a non-profit environmental organization, yet concluding that the difference between emissions from Marcellus shale-gas wells and conventional domestic wells is much less than the EPA and the Cornell authors found.

The team assembled a wide range of information on emissions associated with Marcellus well site investigation, preparation, drilling and completion – what the group terms the pre-production phase. They make the reasonable assumption that the intermediate steps from processing through distribution and the final phase of combustion at power plants is identical for shale and conventional gas, though they also claim to have more accurate information for these parts of the life cycle, based on another Carnegie Mellon study. The researchers also try to account for uncertainties in their data by constructing a range of possible emissions scenarios, and then employing special statistical methods that take into account the impact of these uncertainties on their final figures. The study concluded by comparing the full life cycle results for the Marcellus shale gas to the average life cycle emissions for conventional domestic natural gas.

According to its calculations, Marcellus wells cause an 11 percent increase in greenhouse-gas emissions relative to average domestic gas, exclusive of combustion, and a 3 percent increase when the emissions from combustion are incorporated into the life cycle analysis, figures that are considerably lower than the results reported by the EPA and the Cornell study.

The Carnegie Mellon team also compared their results to the life cycle emissions associated with domestic coal and imported liquid natural gas.  Relative to coal, both conventional natural gas and Marcellus shale gas have lower life cycle emissions, the study concludes.  But if carbon capture and storage were to remove and sequester the greenhouse gases from power generation, then gas, and especially Marcellus shale gas, would have a carbon footprint greater than coal, it says.  The finding indicates that coal has “upstream” greenhouse emissions that are lower than gas, the researchers say.

Of particular importance is the study’s conclusion that relative to imported liquefied natural gas (LNG), emissions from domestic shale gas are about three percent lower. Since the Energy Information Agency had previously expected imports of LNG to rise, and that prediction has turned out to be wrong by virtue of the increasing role played by domestic shale gas, the Carnegie Mellon research injects an important new element into the debate.

Where the Debate Stands Now

Although it might look like the final answer is in, the question is still short of reaching resolution. And the reason behind lingering doubts is the one thing about which all sides agree: that a great deal of uncertainty remains about the accuracy of information on shale-well methane emissions.

Here, for example, are the limitations with which Timothy Skone of the National Energy Technology Laboratory qualifies his analysis of emissions.  They include uncertainties about

• Gas production rates, gas composition and flaring rates, due to variation from formation to formation;
• The effectiveness of  “green” – that is, environmentally preferable – methods and technologies;
• The quantity of fugitive emissions around well heads;
• The greenhouse-gas emissions associated with the production and treatment of hydrofracking fluids; and
• The emissions from changes in land use and building access roads to shale-gas well sites.

It should be noted that Skone’s final estimate of shale-gas emissions is lower than estimates from EPA and Cornell, but he and the Cornell researchers wholly agree that available data suffers from serious shortcomings and further study is needed.

Even IHS CERA’s more strident critique acknowledges the lack of comprehensive data and recognizes that EPA’s new rules for data collection could be “beneficial to all who seek to understand greenhouse-gas emissions from the industry.”  The authors also do not appear to object to EPA’s new source performance standards, which would regulate air emissions during the completion phase of hydraulically fractured gas wells, requiring “green” practices for flaring and capturing methane.  Their only bone of contention is their belief that EPA’s rules do not differ from common industry practice.

With that much uncertainty at the core of the debate, it is difficult to imagine resolving the question unless and until industry reporting of about shale well emissions allows for more valid analyses to take place. If results from accurate emissions total show real benefits over coal and LNG, then at least some of the currently skeptical stakeholders might be more open to accepting the other environmental risks of shale gas.

– Eleanor Saunders

This viewpoint was consistently expressed by solar-energy experts who spoke last month at the Restructuring Roundtable, a forum that meets six times a year in Boston to discuss trends and policies affecting the energy industry and the power grid throughout New England. Despite the present controversy over the bankruptcy of Solyndra LLC – the manufacturer of solar panels that failed after receiving a $535 million federal loan guarantee —  prognostications about the future of solar are bright, said professionals representing both the public and private sectors.

Relevant Global Conditions

The background to this shift in market dynamics was laid out by Chris Porter, a lead analyst with the consulting company Photon Energy. Over the period 2005 – 2011, there was a sixteenfold increase in sales of PVs, fueled chiefly by generous government incentives in Germany, Spain and Italy.  As a result of the heated market, a disconnect developed between the actual cost of producing PVs and their list prices, with the latter rising in response to the policy-driven spike in demand, said Porter.  Buyers continued to purchase PVs despite high price tags, because incentives drove down purchasers’ out-of-pocket expenses, he said.

Porter explained further that a bottleneck in the supply of polysilicone, a key component in the PV manufacturing process, also made an important contribution to the market imbalance.  In response, industry began investing to boost its production of the compound, which is now expected to expand fivefold by 2015 from where it was in 2009, he said.[1]

But just as the industry was kicking into high gear, circumstances in European began to dampen demand for PV. The important German market reached a saturation point after having installed about 25 gigawatts of solar power, the equivalent of approximately 15 to 20 percent of the country’s generating capacity and 30 percent of its peak load demand.  And other European countries like Spain and Italy, who previously had expanding solar markets, are not able to take up the slack because of Europe’s continuing financial crisis, said Porter.

Porter anticipates that 2011 will see the first leveling or even contraction of demand, which should cause prices to fall to between about $1.20 per watt (for low-cost solar panels) and $1.50 per watt (for more expensive, high- efficiency U.S.-made panels).

With European markets less active and the Chinese market largely closed to outsiders, many large solar developers are planning to expand into the U.S., and one of the most attractive regions is the Northeast because of its high electricity rates and large market size, said Porter.  The challenge for U.S. policymakers will be a classic “Goldilocks problem”: how to prevent the market from getting too “hot” as it did in Spain, Italy and other European countries, while not letting it become too “cold,” he said.

An Answer to the “Goldilocks Problem” in Massachusetts

Many experts believe that the new Massachusetts approach to expanding PV installations will achieve the sort of balance that Porter recommends. Through the careful design of the Solar Carve-Out component of its Renewable Portfolio Standards, the state should be able to create a market that is neither “too hot” nor “too cold,” said Dwayne Breger, director of the renewable and alternative energy division at the Commonwealth’s Department of Energy Resources. The carve-out is a market-based incentive program that aims to support residential, commercial, public and nonprofit entities in developing 400 megawatts (MW) of solar power across the Commonwealth. The carve-out should contribute the bulk of the nearly 500 MWs of electricity that the state’s combined solar programs [2] are expected to create by 2016-2017, a target well beyond the initial 250 MW solar goal set by Gov. Deval Patrick in 2007.

Like other states, Massachusetts has a requirement for utilities to hold a certain amount of solar power within their electricity portfolios, either by developing their own solar projects or providing an alternative compliance payment through the purchase of Solar Renewable Energy Credits (SRECs) from projects that have been qualified by the state’s Department of Energy Resources (DOER).[3] The SRECs, which represent one megawatt-hour of produced solar energy, are a source of financial support for project developers that comes from the private sector rather than from state government.

Beginning in 2010, the carve-out program set an initial annual minimum standard of solar generation, equivalent to 30 MWs of capacity, that was divided among utilities according to their market share within the state, Breger said. Each year, the minimum standard increases by approximately 30 percent, until generating capacity reaches a cap of about 400 MWs, at which point new project applications will be fed into the regular RPS structure, he said.

But beyond these basics, the Commonwealth’s program design differs from other states’ approaches through a two-tiered market structure for SRECs, which contains innovative self-correcting mechanisms that experts believe should resolve the “Goldilocks problem.”

In the first-tier market, the state offers SRECs, good for a one-year term, at a ceiling price that cannot be lowered by more than 10 percent annually, a figure that DOER has recently proposed be revised downward at the behest of market participants. [4]  The system’s pricing structure provides sellers with reasonable certainty about the income they will derive from SREC sales. Utilities may choose to purchase however many of the available SRECs they want at this price, which in 2010 was $600 and in 2011 $550.

For SRECs that haven’t been sold at the ceiling price, there is a second option, an annual state-run auction.  Any project may choose to put its remaining certificates into an auction account that has a life of up to 10 years. The auction market sells SRECs from these accounts at a set floor price of $300 per megawatt-hour, and the purchased certificates have a shelf-life of two years versus the one- year term in the first-tier market.  Utilities’ bids correspond to the number of SRECs they want to purchase.  The auction ends when either all certificates are sold or no more bids are forthcoming.  If SRECs are unsold at the end of round one, another round of bidding takes place, with the remaining SRECs reminted as three-year certificates.

But if the second auction doesn’t exhaust the remaining SRECs, then one of the key adjustment mechanisms kicks in.  It allows for the existing minimum standard of solar generation to be increased by the exact amount that would oblige utilities to buy all the unsold certificates.  Thus, a “too cold” market is warmed so that project developers are not left with unsold SRECs and a financial gap.

A second fine-tuning mechanism permits the state to adjust the number of years that new qualified projects may be part of the auction market.  Because of the time lag in getting projects up and running, there are more buyers than sellers at present, said Breger, and the opt-in term has been set at 10 years, giving developers a long-term financial guarantee.  But projects are coming on line rapidly and that term could be adjusted accordingly, he said.  If too many projects are being built, a shortened term would weaken the financial guarantees for developers, and the “too hot” market should cool down.

Once the carve-out program has been operating long enough for its fine-tuning mechanisms to be triggered, it will be possible to see whether the Massachusetts solution works as well in practice as in theory.

Broader New England Prospects

Spokesmen from Constellation Energy and the Solar Energy Business Association of New England completed the picture of solar’s prospects in New England as a whole.  Both agreed that the policies set up by Massachusetts had generated substantial activity, but need some adjustments to maximize growth.  With respect to the rest of the region, they described the potential for growth as moderate to optimistic for Connecticut and Vermont but low for New Hampshire and Maine, given existing policies. Rhode Island, though a small market, could prove interesting because of a recent unexpected legislative move, the business association spokesman said.

With 59 MWs of solar installed, 353 MWs in the interconnection queue [5] and an undersupply of SRECs from qualified projects for the alternative compliance market, Massachusetts is likely to continue its growth, said Dan Leary of Nexamp, a company that builds, owns, and operates renewable energy projects.  That growth is reflected in the more than 200 solar installation and development companies active in its market, he said.

But Leary, also president of the Solar Energy Business Association of New England, and Bryan Miller, a vice president of energy policy at Constellation Energy, concur that some policy snags will hold back projects.  These include uncertainties created by the expiration of tax exemptions associated with SREC costs from 2017 on, the cap on net-metering credit as it is currently set, and ambiguities or contradictions in net-metering regulations that may unintentionally disadvantage public entities interested in hosting solar installations.

Connecticut

Next to Massachusetts, Connecticut’s solar market offers the brightest outlook in the region, following the passage of sweeping energy reform in June through SB1243, speakers said.  The law expands the resources that can go into the state’s Clean Energy Fund and creates a quasi-public authority, the Clean Energy Finance and Investment Authority (CEFIA), to oversee it.  CEFIA will be responsible for developing programs to finance and support clean-energy investment, manufacturing, research and development, and for creating a program for zero-and-low emissions renewable energy credits (ZRECs or LRECs).  The law also mandates the creation of a residential PV program to produce 30 MWs of installed solar energy by 2022, and directs electric companies to develop long-term contracts by late 2012 for the purchase of ZRECs from clean-energy projects. They include solar installations that are one MW or less in size, with preferences given to technology originating in Connecticut.

Since the program is just being rolled out, many details remain to be filled in.  Miller says that the state would benefit from making several small changes at the outset, such as instituting a ZREC cap per entity to prevent market domination by a few players, establishing a property tax exemption for projects and allowing municipalities to receive net-metering credit for solar power installed through Power Provider Agreements or leases.

Vermont

Vermont is the other New England state that both Miller and Leary say will offer a moderate level of growth, consistent with its feed-in-tariff, which was established by legislation enacted in 2009.  But Miller said that only two or three out of a dozen awarded Vermont projects are actually under construction because of financial disadvantages associated with the state’s current tax structure. He suggested several fixes such as a property tax exemption, an alteration of the tax basis like the one available for wind and hydro projects, or the provision of grants in lieu of tax incentives.

Rhode Island

Leary also expressed interest in the Rhode Island market, based on its potential for growth in distributed generation. This opening was created by the June passage of a law that establishes a limited feed-in-tariff for 40 MW of distributed generation from wind energy, solar PVs, and aerobically produced biogas.  The law instructs the state to develop standard offer contracts for any such projects under five MWs in size, with the initial contracts for five MWs worth of generation to be ready by the end of 2011 and final contracts that meet the goal of 40 MWs overall to be concluded in 2014. Pricing for each type of renewable resource will be determined by an oversight board, and project costs may be recovered from the distribution system’s ratepayers.

   – By Eleanor Saunders

The Federal Energy Regulatory Commission (FERC) finalized an important rule on U.S. electricity transmission planning and cost allocation in July 2011, and now is responding to questions and concerns about the regulation’s implications for states, utilities, consumers and other affected parties.

The commission asserts the order’s provisions will bring about a more open and coherent planning process, structured around clearly articulated general principles that permit the flexibility necessary for accommodating divergent regional needs and practices.  But the reaction to FERC’s new rule has varied greatly among stakeholders operating in different regulatory environments. [1]

Order No. 1000, entitled Final Rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities (henceforth, Final Rule), tackles three major issues:  transmission planning, cost allocation for new transmission projects and the status of non-incumbent developers — that is, entities not among the current transmission developers or operators in a region that wish to enter the market.

A central provision of the Final Rule requires that transmission planning take place at the regional level, with broad stakeholder input and coordination between neighboring regions.   Although regions will retain a great deal of autonomy in defining the details of their plans, all must identify which state and federal public policies have implications for their transmission needs, and must consider these policies when evaluating proposals for specific projects.

The Final Rule further stipulates that regions develop clear cost-recovery methods for any new facilities deemed to satisfy regional needs. Although it does not mandate the use of any specific approach, the order does spell out general features, such as requiring that costs only be allocated to those who directly benefit from a given project and that a region’s method of identifying beneficiaries and assigning costs be fully transparent.

The rule represents the next step in a sequence of FERC regulations, including orders number 888 from 1996 and 890 from 2007, that aim to remove discrimination in transmission planning and ensure that less costly and more efficient power supplies reach consumers, Mason Emnett, associate director of FERC’s Office of Energy Policy and Innovation, told an audience of energy professionals at a forum in Boston on September 16.

Emnett, whose office was instrumental in developing the new rule, also stressed that despite its more than 600 pages of text, the order seeks only to establish a general framework for regions to use in planning.

“The future is in your hands,” said Emnett.   He noted, for example, that “you can define your own regions,” although the FERC anticipates that current regional transmission organizations (RTOs) or independent system operators (ISOs) will provide relevant templates in at least some parts of the country.

While the traditional principles of reliability and cost-effectiveness will continue to be important determinants of regional plans, relevant public policies will now have an explicit role to play in defining transmission needs.  But it is up the regions to determine which policies are applicable, Emnett said.  If a region decides, for example, that an increase in renewable energy resources is important, transmission may be needed to integrate new renewable supplies rather than simply to improve reliability, he said.

The rule also aims to promote competition that maximizes the cost-effectiveness of new facilities.  Toward that end, regional planning authorities must remove obstacles or cease practices that would disadvantage proposals from nonincumbent developers, such as the existing right of first refusal that has been extended to incumbent players, Emnett said.

Emnett’s presentation on behalf of FERC at the September 16 forum was followed by responses  from representatives of several major New England stakeholder groups –the states, utilities and environmental organizations.  The speakers conveyed largely favorable reactions toward the reforms, but raised questions about various provisions.

 Peter Flynn of National Grid praised the order for “being pro-customer and providing a model of federalism” in the way that it addresses transmission planning.  Flynn, who is president of National Grid’s FERC-regulated businesses, also lauded FERC’s decision to develop principles on a general rather than project-oriented level.

“The rule leaves room for the states to play a leading role in determining what public policies should enter into transmission-planning discussions, though it seems clear that RPS requirements are a stand-out candidate since they often stimulate a need for additional transmission,” said Flynn.

Seth Kaplan of the Conservation Law Foundation also addressed the public-policy requirement, which he said is squarely within FERC’s jurisdiction because the mandate is not overly general, calling only for consideration of public-policy requirements in light of their specific impact on transmission planning and costs. Thus, the rule is consistent with prior case law such as Mass Electric Company v. Department of Public Utilities, where the court found that a public utility commission may direct a utility to avoid conditions that the commission “reasonably anticipates will impose costs on the utility and be detrimental to the interests of ratepayers,” said Kaplan, who is vice president for policy and climate advocacy.

If utilities or other transmission planners fail to take into account a state’s renewable portfolio standard, or other public-policy requirements, that omission could hinder the most cost-effective approach to planning and ultimately lead to higher prices for ratepayers, he said.

Kaplan went on to highlight the challenges inherent in the two-step process that the Final Rule sets up to first, identify relevant public policies and then, integrate those policies into transmission planning and project selection. The flexibility permitted in relation to the second step creates the risk that public-policy requirements could be treated with a wink-and-nod kind of paper compliance, said Kaplan. He compared their potential fate to that of the mechanism for grid upgrades intended to provide ‘economic benefits’ for New England electricity customers. “While the provision sits on the books, it is never used — in sharp contrast to the mechanism for planning and funding ‘reliability upgrades’, which has been used to move forward billions of dollars of projects,” he said.

Heather Hunt, executive director of the New England States Committee on Electricity (NESCOE), noted that the New England states have already been engaged in the type of coordinated planning that the order requires, so that the region’s compliance with the Final Rule may be smoother than in other parts of the country.  As evidence, she cited the 2009 New England Governors’ Renewable Energy Blueprint, which explores the potential for regionally coordinated procurement of renewable energy and transmission siting.

But she also pointed to complications associated with ambiguity in the rule’s requirements, including the difficulty of specifying the impact of state laws and regulations on transmission when, for example, renewable portfolio standards can be satisfied by alternative payments as well as new generation or the amount of energy efficiency made use of in a given state can be affected by policies and decisions about loading order.

NESCOE plans to seek out stakeholder input on the question of relevant public policies for the region as a whole, and to examine how non-transmission alternatives like energy efficiency and demand response measures, only minimally addressed by the Final Rule, may play out in regional transmission planning and developer cost recovery, Hunt said.

For example, in a request for rehearing filed with FERC, the Coalition for Fair Transmission Policy, an association of seven investor-owned utilities serving over 28 percent of U.S. electric customers, said that “the Final Rule could result in higher costs to many consumers, [pre-empt] public utility and state prerogatives to determine and decide what generation resources best meet the reliability and economic needs of consumers …, and [cause] inefficiencies in competitive electric markets.”

Commenting on the public-policy requirement specifically, the group worries that regional planning might operate in a top-down way, assigning benefits that are “speculative” and “beyond the typical planning horizon,” and allocating costs on that basis rather than addressing planning decisions through a bottom-up process led by utilities, who are most familiar with resource needs.

The varying reactions to the Final Rule may reflect at least in part the very different market structures within which stakeholders operate.[3]  Northeastern, mid-Atlantic and midwestern states along with California are already organized under independent third-party RTOs or ISOs, which oversee regional transmission planning and wholesale electricity markets.  In contrast, southeastern, southwestern, inter-mountain and northwestern states have retained traditional vertically-integrated utilities that control both transmission lines and dispatch of power to the grid.  Besides developing and operating transmission, these utilities own generating plants that supply electricity to the grid, all under the jurisdiction of state regulatory commissions.

For companies and states where the traditional structure holds sway, FERC’s requirements for regional planning and full transparency necessitate a huge reorientation.  They directly challenge a model where state utility commissions decide on the appropriateness of transmission proposals and cost allocation, planning to a substantial degree takes place within utilities and integrated resource plans are confidential corporate documents.

But Emnett noted that these changes do not come out of the blue.  FERC has been invested in moving toward greater transparency and consistency in U.S. transmission planning since publishing Orders No. 888 and 890. The new Final Rule simply makes the principles clearer and provides a more detailed framework for doing so, while still allowing regions a fair amount of latitude, he said.

According to FERC Commissioner Marc Kaplan, who addressed objections raised by Coalition in an interview for E&E TV’s OnPoint on September 27, the Final Rule is a document that has “brought order out of chaos.”  Spitzer focused specifically on the question of cost allocation, and described the cacophony of positions that might have determined policy before the new order  was finalized – ranging from a U.S. Senate bill that “would have provided for interconnection-wide cost allocation” to a proposal to “limit how regions could impose cost allocation on their own ratepayers.”

The chaos and uncertainty have had a negative impact on the development of both transmission and generation, to the ratepayer’s detriment, he said.  With the Final Rule, FERC’s bipartisan group of commissioners gave unanimous support to a path midway between the extremes, Spitzer said.

As the debate goes on and commissioners consider filings for a rehearing of rule provisions, FERC will offer three fall webinars to help regions in developing their compliance plans.  Regional plans must be filed within one year of the effective date of the Final Rule, and interregional plans for common cost allocation methods for any transmission projects that may be selected by neighboring regions must be filed within eighteen months.

How the commission ultimately clarifies or reworks details of the Final Rule will be of great importance for the states and the shape of the country’s transmission backbone in the coming decades.

    – By Eleanor Saunders