Even top federal energy regulators are worried: “The collapse of generation additions and the threat that poses to reliability and just and reasonable wholesale power prices in New England cannot be ignored,” warned Joseph Kelliher, chairman of the Federal Energy Regulatory Commission in a prepared statement. “I do not want to see the California crisis visited upon New England, and I do not want to see the commission criticized for not acting to assure reliability.”

Policymakers are scrambling for quick solutions. For distributed energy, this means new opportunity through state incentives being rolled out in 2006.

Why New England Needs Power
If the lights are to stay on, the region will need as much as 1,900 MW of additional capacity or distributed energy by 2008, according to ISO New England, the grid operator. While the real crisis is still at least two years off, problems already have come home to roost. Bracing for what is expected to be record-breaking demand—even if temperatures remain normal—the grid operator has found it necessary to create an emergency power management plan for the winter. The plan ramps up demand response and conservation measures.

How did this shortage come to be? The Northeast crams one-fifth of the nation’s population into less than 2% of its land area. So new energy facilities inevitably impinge on schools or homes, or obstruct scenic views. Almost any attempt to build large fossil-fuel power plants or major transmission lines causes outcry from property owners. Renewable energy proposals fare no better—indeed sometimes worse. Four years ago, Energy Management Inc., a Boston-based developer, announced it would build the United States' first offshore wind farm in Massachusetts’ Nantucket Sound. But the 130-turbine project has yet to secure its key regulatory approval, as it battles against wealthy shoreline property owners, who in 2004 alone, spent $5 million to stop the project.

Public acceptance isn’t the only difficulty faced by those trying to build large power projects. It is not easy for developers to secure financing, following the region’s post-Enron meltdown that forced project cancellation and in some cases bankruptcies. In addition, developers say inadequate capacity pricing rules make it tough to earn an appropriate return on investment. As a result, generating companies aren’t putting money into New England. In fact, in energy-hungry Massachusetts, applications for power plants are so scarce, it’s been five years since the state Energy Facilities Siting Board issued a new permit.

What is the solution to New England’s power woes? One thing is for certain: New England can’t “build its way out” of the problem and needs to pursue a range of resources beyond traditional power plants, according to Susan Tierney, former assistant secretary of policy at the US Department of Energy, and now a managing principal with the Analysis Group of Boston. She co-authored a November 2005 report with Paul Hibbard, on behalf of the advocacy group, the New England Energy Alliance. The report calls for New England to act quickly and aggressively to address its lack of energy infrastructure.

“Like most modern economies, New England takes for granted that its energy infrastructure will provide the power and other fuels needed by households, local business, and industries. The region is at a point, however, where we can no longer take the issue for granted,” said New England Energy Infrastructure, Adequacy Assessment and Policy Review. “Right now, many signals coming from this region’s market rules and regulatory policies present an uncertain investment climate at best—and at worst, send the message to take the investment dollars elsewhere. Shaping energy policy and developing energy infrastructure projects take time, so action is needed now to avoid problems in the near future.”

Throughout New England, policymakers are heeding such advice and looking at quick ways to supplement traditional resources with alternatives like distributed energy. These states are exploring a range of financial and regulatory incentives to bring more distributed generation, demand response and energy efficiency into the fold as soon as possible.

Connecticut Seeks New DE Investment
No state needs to take action more quickly than Connecticut. FERC says that the state’s southwest region, near New York, is one of the most troubling areas of the national grid. The area has difficulty importing power because it lacks transmission lines. At the same time, its power plants tend to be old, prone to outages, and nearing retirement. FERC has approved special arrangements to keep the plants running. Known as reliability must-run contracts, these deals give the plants higher than ordinary capacity payments to prevent them from retiring. The problem is, utility ratepayers must shoulder this expense, and it’s a large one – about $100 million in 2005 for customers of the state’s largest utility, Connecticut Light & Power. On top of that, Connecticut already has among the highest electricity rates in the country, ranking behind only Hawaii, New York, and Massachusetts, according to statistics by the US Energy Information Administration calculated through August 2005.

If the lights stay on, the region will need as much as 1,900 MW of additional capacity or distributed energy by 2008.

The high cost of power is taking its toll on the state’s manufacturing sector. Kimberly-Clark, manufacturer of Kleenex, warned state public utility commissioners in October that reducing energy costs is “absolutely essential to the long-term survival” of its New Milford, CT, manufacturing plant, which has the highest power costs of any of the corporation’s North American facilities.

Kimberly-Clark is taking a hard look at installing combined heat and power to reduce its costs. “Skyrocketing energy costs are impeding the New Milford facility’s ability to compete for capital investment and production opportunities against other K-C facilities and consequently, impeding K-C’s ability to compete with domestic and international competitors,” the company said in a filing to the state Department of Public Utility Control (DPUC) in October. “Onsite distributed generation represents an instrumental energy cost management tool for the New Milford facility.”

In an attempt to keep companies like Kimberly-Clark in the state, reduce strain on the grid, and bring electricity costs down, Connecticut Gov. Jodi Rell last summer signed into law “An Act Concerning Energy Independence.” Among other things, the bill creates financial incentives for customers to invest in distributed energy. It also gives utilities reason to support such projects – or at least not fight against them. In addition, the bill takes the unusual step of putting combined heat and power on a more equal footing with renewable energy when it comes to state funding.

State regulators spent the latter half of 2005 readying programs that comply with the new law. One program encourages businesses to install distributed generation by requiring that utilities grant one-time capital subsidies for the installations. The subsidies range from $200 to $500 per kW of generating capacity. Since the idea behind the program is to decrease costs for all customers, applicants only receive the subsidies if the distributed energy project reduces utility congestion charges. Those charges cover the costs of reliability must-run contracts and other expenses related to Connecticut’s lack of transmission and capacity.

The program is open to plants with an output of no more than 65 MW, as well as conservation and load management, including peak reducing and demand response systems. So that utilities will support the DE installations, they too receive incentive payments. The funds go to educate, assist, and promote investments in distributed energy. Specifically, utilities receive one-time awards of $200 per kW for resources developed by Jan. 1, 2008, $150 per kW by Jan. 1, 2009, $100 per kW by Jan. 1, 2010, and $50 per kW after that. The state will grant the awards after projects begin operation.

The new law also gives distributed energy an opportunity to compete, along with other resources, in a solicitation for power that the DPUC is scheduled to issue in 2006. The state will seek resources that can reduce congestion charges from May 1, 2006 through Dec. 31, 2010. Utilities can compete in the solicitation. But if they do not win, the law once again provides them with monetary incentives to support the winners. Specifically, they receive grants to cover any expenses associated with transmission and distribution upgrades necessary to accommodate a distributed generation facility or power plant. If the project begins operating by Jan. 1, 2008, the award is $25 per kW; by Jan. 1, 2010, $15 per kW, and by Jan. 1, 2012, $ 5 per kW.

The Connecticut law also:

• Exempts new DG projects from paying backup charges to utilities if power from the unit is available to the grid during peak periods.
• Requires utilities to give rebates for gas delivery charges to customers using distributed generation.
• Calls for the state DPUC to arrange long-term low interest loans to help customers cover capital costs for distributed generation and advanced power monitoring and metering equipment.

Once a year, starting in 2007, the DPUC will assess how well the state is doing in developing distributed generation and how well the projects contribute to fuel diversity, transmission support, and energy independence.

The law also gives combined heat and power projects some new goodies. Specifically, it allows the Connecticut Clean Energy Fund, which oversees the state’s renewable energy funds, to channel money into CHP projects. In addition, CHP and energy efficiency projects can produce renewable energy certificates, just as wind power, solar, and other renewable energy technologies now do. This creates an additional income stream for distributed energy projects and can help them acquire financing.

Utilities and suppliers buy the certificates to meet the state’s renewable portfolio standard, a requirement that a certain percentage of their power come from clean energy. The trading program now has two classes of certificates: Class 1 for wind, solar and other renewables and Class II for trash-to-energy projects. The new law establishes a Class III resource, which includes certificates from CHP projects built by commercial and industrial facilities that have an operating efficiency of no less than 50%. As of Jan. 1, 2007, utilities and power suppliers must begin getting 1% of their power supply from these Class III resources. The amount increases by 1% in each of the following three years. Those who do not secure enough of the certificates to meet the standard must pay up to a 5.5 cents/kWh fine.

Vermont Even Better?
While Connecticut is one of New England’s largest energy markets, Vermont is among its smaller players, with only about 1,000 MW of peak load. Despite its size, Vermont has developed some big ideas when it comes to distributed energy. These are “enlightened policies of the first order” in the words of Sean Casten, president of Massachusetts-based Turbosteam Corp., which designs, manufactures and installs backpressure steam turbine-generators.

The policies emerged from “An Act Relating to Renewable Energy, Efficiency, Transmission and Vermont’s Energy Future,” signed into law by Gov. Jim Douglas in June. The law requires that state policymakers and utilities work together to increase renewable energy and combined heat and power.

The state legislature took up the issue of Vermont’s energy future following a battle over a $129 million transmission line in northwest Vermont. Much like Connecticut’s southwest, the area is considered highly vulnerable to blackouts. To fix the problem, the Vermont Public Service Board approved construction of the 115/345 kV line. But it did so grudgingly. In the June 2005 decision, the board lectured the Vermont Electric Power Company, the utility in charge of transmission, for coming to the table so late with the project proposal. With more time, the board said it might have pursued less costly alternatives to the line, such as distributed energy. However, given the pressing nature of Vermont’s reliability problems, the board said it had little choice but to approve the transmission project. Adding salt to the wound, several months later the utility reported the project would cost about $78 million more than it originally expected.

The most publicized aspect of the new law requires that the state set up a renewable portfolio standard. In Vermont’s case, utilities must come up with enough renewables in 2012 to equal the amount their load grew over the previous seven years, or 10% of the utility’s 2005 retail electric sales, whichever is lower. The bill does not include combined heat and power as a renewable. But what it does do, says Casten, is give utilities an opportunity to forego complying with the RPS by building cogeneration instead. Specifically, the utilities have a choice of complying with the RPS in 2011, or entering into contracts for renenawbles or congeneration before that date. This opens the opportunity for cogeneration developers to propose immediate projects to utilities.

The bill also requires that utilities include distributed energy in least cost planning. If a utility proposes a new substation, it must prove that the project is more cost-effective than distributed energy or other options. “It forces them to look at DG as one of the options,” he said.

In addition, the state must create interconnection standards by Sept. 1, 2006 for distributed generation units that are 50 MW or less. And finally, the bill strips away rate incentives that discourage efficiency in utility supply plans. Specifically, the law attempts to end a long standing bias in utility rate structures that work against distributed energy. Since distributed energy decreases energy usage, it cuts into utility sales and revenue, often leaving utility’s with a less-than-friendly posture toward the measures. The law reworks the rate structure so that the utility does not come up as a loser if distributed energy is a winner.

State regulators are in talks with utilities and other parties to implement several of the laws provisions later in 2006. Even though the new rules are unlikely to be finished before September, the state’s third largest utility already has pledged to replace 20% of its power purchase contracts with cogeneration.

 “Time will of course tell what the long-term impact is, but Vermont is unique for focusing on getting policy signals right with respect to on-site generation,” Casten said.

Mixed Opportunity In Massachusetts
Massachusetts is the largest electric energy market in the seven-state region, with a peak load that exceeds 11,000 MW. The state offers rich potential for distributed energy because of Boston’s many commercial buildings. However, Boston sees little cogeneration development, largely because of unfavorable regulations, according to Casten. The specific problem is back-up fees charged by Boston-based electric utility, NSTAR.

However, the Massachusetts DG Collaborative, funded through state renewable energy money, has been working on improving conditions for distributed energy in the state. The group in 2004 won regulatory approval of interconnection standards and is now working on a range of other issues, including the role of distributed generation in utility planning, and its advantages at specific sites.

The state also has an aggressive renewable portfolio standard, which is spurring development of small solar, wind and certain biomass projects. Because Massachusetts places strict limits on the kind of resources that can produce renewable energy certificates, the certificates trade at high prices—about $50/MW. These high prices give renewable DG initiatives a better chance to secure project financing.

In addition, Massachusetts set up a systems benefit charge as part of industry restructuring in the late 1990s. Utility customers pay the charge within their monthly bills. The money pays for a variety of programs through the Massachusetts Technology Collaborative, which promotes renewable energy. The program includes $8.9 million over three years to encourage installation of distributed renewable energy units that are larger than 10 kW and located at commercial, industrial, institutional, and public facilities. The MTC recently issued a request for proposals seeking such resources and expects to begin choosing winners in April.

Sticker Shock A Good Thing?
Many of these programs can start helping New England over the next couple of years. The problem is, the region needs help now. Peak demand is expected to break records this winter, even under normal weather conditions. As a result, the grid operator instituted a winter contingency plan, which includes use of distributed resources. Under the program, ISO New England pays electric customers to reduce load or make their distributed energy available during high demand periods. As of September 2005, the ISO already had 500 MW of demand response resources. However, it became clear by October that the region would need an additional 450 MW for the precarious winter ahead. Those who can respond in 30 minutes are paid between $8 per kW and $14 per kW.

EnerNOC, a Boston-based demand response company, quickly signed up 100 MW of customers for the winter program. They include telecommunications companies, data centers, universities, industrial facilities, hospitals, insurance companies, municipalities, and state government facilities. “The call to action has been clear, quick, and emphatic and our customers responded enthusiastically, wanting to preempt possible business disruption and to help the grid,” said Gregg Dixon, EnerNOC’s vice president of marketing and sales.

“This is an unprecedented response for enabling new resource capacity in such a short period of time and illustrates that customers have a strong propensity to participate in demand response, especially when market rules are properly defined and customer incentives are clear.”

As a longer-range solution, the ISO has proposed a locational installed capacity plan (LICAP), now under review before FERC. The idea is to pay more for capacity in geographic zones where it is needed. While the plan is geared toward large power plants, distributed energy advocates are pushing for cogeneration and green power to also receive the incentives “If you really want these alternative resources to step up, they need to be part of the game,” says Patricia Stanton, director of renewable energy markets for Conservation Services Group, a Westborough, Mass. company that offers a range of distributed energy services.

Fear of outages is spurring interest in distributed energy. So is the almighty dollar. Since 40% of New England’s electric generation comes from natural gas-fired plants, the region has been hit hard by the skyrocketing natural gas prices that followed hurricanes Katrina and Rita.

As a result, winter electric rates are very high this year; for some large customers even doubling.

Indeed, it is the convergence of possible blackouts, high costs and regulatory support that seems to be creating fertile ground for distributed energy in New England. Alan Nogee, clean energy program director for the Union of Concerned Scientists, says he expects interest in energy alternatives “to spike” right along with people’s electric bills., CSG’s Stanton sees state incentives giving a confidence boost to commercial and industrial customers who were on the fence about pursuing distributed energy.

Indeed, Turbosteam’s Casten says the next two to three years ought to be “very positive” in New England. For cogeneration, sales are already up over last year.

The good news is likely to continue, as long as businesses don’t flee the area before distributed energy incentives take effect.

“It seems like not a month goes by lately that another northeastern utility doesn’t announce a 20% to 30% rate increase,” said Casten. “This will have a huge impact on CHP deployment, but only if the double whammy of fuel and electric rate increases doesn’t drive local businesses to move their operations, taking their CHP-critical thermal loads with them.”  

ELISA WOOD is an energy writer based in Virginia.

DE - May/June 2006