NYPA announces Albany microgrid plans

The New York Power Authority has announced plans to develop a microgrid to supply steam and electricity to the Governor Nelson A. Rockefeller Empire State Plaza in Albany.

NYPA, officially known as the Power Authority of the State of New York, is a state-level public power organization, operating power plants and transmission lines.

On May 22, 2017, NYPA announced its plans to convert a former waste-recovery steam plant located in Albany into a site for two new 8-megawatt natural gas-fired turbine generators with dual fuel capability.  The generators will be able to supply local needs, or sell power into the wholesale market, with the microgrid capable of operating in sync with the main grid or as an independent "island."  According to NYPA, the "resilient power generation facility will enable government services to continue in an emergency while the Plaza can be used as an emergency shelter for Albany residents."  The project is expected to supply 90 percent of the power for the state office complex, to save more than $2.7 million in annual energy costs, and to avoid the annual emission of 25,600 tons of greenhouse gases. 

The New York State Office of General Services will finance the project, supported by $2.5 million from NYSERDA.  NYPA has issued a request for proposals by developers; proposals are due to NYPA on July 13, with awards expected this fall.

Study quantifies New England distributed generation, growth

Distributed generation – small-scale electric generation facilities installed at consumer sites – plays a growing role in the resource mix used to meet society’s needs. Typical distributed generation assets include solar photovoltaic panels and co-generation or combined heat and power units developed at homes and businesses. A study released yesterday found that distributed generation capacity in New England could roughly triple in the next decade – and that regional electric grid operator ISO New England Inc. needs to account for distributed generation in its planning.

As New England’s regional transmission organization, ISO New England plans for and coordinates the development of electric transmission infrastructure. In the past decade, New England ratepayers have spent approximately $5 billion on transmission additions and expansions. ISO New England’s 2012 Regional System Plan calls for the investment of another $6 billion in transmission projects in the coming years. As a result, regional transmission rates roughly tripled between 2006 and 2010, and continue to grow.

ISO New England’s plans are based on its forecasts of future system needs, including anticipated load growth and changes in the electric generation portfolio used to satisfy customer demand. But ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development. According to “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning”, prepared by Synapse Energy Economics Inc., ISO New England is significantly underestimating the current and potential distributed generation in New England, particularly with respect to solar photovoltaic resources.   According to Synapse, “This practice results in the ISO ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”

ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection. But Synapse found that over 980 megawatts of distributed generation assets are already installed in the six New England states. By 2021, Synapse predicts that this could grow to over 2,855 MW based on existing policies and development trends.

Synapse Energy Economics, Inc., Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning, at page 19.

State policies and the favorable economics of distributed generation projects are driving their adoption on a wider scale than in previous years.  For example, after exceeding its previous solar photovoltaic target, Massachusetts recently increased its target to 1,600 MW.  Renewable portfolio standards, net metering policies, and feed-in tariffs all contribute to the proliferation of distributed generation, as does a cost differential that makes natural gas-fired cogeneration more cost-effective than burning oil for heating and purchasing electricity in commercial and industrial applications.

Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”

Whether and how ISO New England and the states take distributed generation into account remains to be seen, but if the trends noted in the Synapse report play out to even a modest degree, non-transmission alternatives such as distributed generation may be able to limit further increases in regional transmission rates.

Pro football goes green?

This year the National Football League's Philadelphia Eagles plan to install renewable electricity generation at the Eagle's home stadium.

Under the deal announced earlier this spring, energy and utility giant NRG will install 11,000 solar panels and 14 small-scale wind turbines at Lincoln Financial Field in Philadelphia.  NRG reportedly plans to install solar panels along the south and west sides of the stadium as well as in parking lot space, with wind turbines lining the stadium's north and south sides.  Construction is supposed to be complete by the end of 2012.

Sporting facilities like pro football fields typically consume most of their electricity during the relatively few days of the year when they are used, so these renewable electric generation assets may never fully power the Eagles' field during a home game.  At these times, the stadium will most likely continue to draw power from the utility electric grid.  For this reason, it may be no coincidence that the deal also calls for NRG to become the official supplier of grid power to the stadium.

On the flip side, the solar and wind generation will likely produce most of its power when the stadium demands relatively little power, making Lincoln Financial Field a potential candidate for a net metering program such as Pennsylvania has enacted.  Over an entire year, reports suggest that the solar and wind assets proposed for Lincoln Financial Field will produce about six times the power used during all Eagles home games.

The NRG deal is not the first proposal to develop clean energy facilities at the Eagles' stadium.  In 2010, the Eagles announced a similar partnership with Solar Blue, which would have included a natural gas-fired cogeneration power plant in addition to solar and wind generation.  That project was ultimately scrapped.

Nevertheless, if the NRG project happens, the Eagles will join a growing trend of professional sports teams seeking to green their image, improve their sustainability, and cut their energy costs. 

Demand response, customer-provided grid support

This summer, the electric grid has largely weathered the increased demand for power during heat waves.  Grid operators have a variety of tools to ensure sufficient energy supply to meet peak demands.  In recent years, the smart-grid star in the grid's toolkit has been demand response: programs that allow customers to respond to signals about the scarcity of electricity by temporarily reducing their consumption from the grid.  This summer, customer-provided demand response has not only kept the lights on, but has also reduced society’s energy costs by reducing the need for the most expensive marginal peaking generation units.

Last March, the Federal Energy Regulatory Commission issued a landmark ruling that demand response should be compensated fairly.  In this ruling – Order No. 745 – FERC held that demand resources should be paid at market-based prices when two criteria are met: capability and cost-effectiveness.  When demand resources can displace the need for bringing additional generation online, and when doing so lowers our grid costs, Order No. 745 requires organized wholesale energy market operators to pay demand response resources for the full value they provide to the grid.

Now, some regional grid operators are proposing major changes to their demand response programs.  While some of these changes are designed to comply with Order No. 745, other changes seek to place new limits on who can participate in demand response.  For example, northeastern grid operator ISO New England has asked FERC to approve its proposal to eliminate the demand response value provided by consumers capable of using existing on-site generation to produce power to support the grid during times of crisis.

Decades of federal and state policy have supported investment in distributed generation projects, ranging from micro-combined heat and power (micro-CHP) and cogeneration to small and medium-sized wind, rooftop solar photovoltaic systems and even fuel cells.  Distributed generation has a strong history of policy support, but if FERC accepts ISO New England’s proposal to limit behind-the-meter generation’s ability to provide demand response, the region will need other resources to keep the lights on during times of peak demand – new generating units, transmission lines, and substations.

FERC has docketed ISO New England’s request as Docket No. ER11-4336-000, and is accepting public comment through 5:00 pm Eastern time on Friday, September 09, 2011.

Thomas Casten on CHP

I recently read an interesting article which aims to identify obstacles to broader use of combined heat and power (CHP) in the Nov.-Dec. issue of Cogeneration and On-Site Power Production. The article by Thomas Casten notes that despite the potential to cut US emissions by 20% and save consumers $80 to $100 billion per year, US markets remain dominated by the central generation plant model - a model whose overall generation efficiency is about 33%.

Casten points to ratemaking policy for the electric industry as a cause of this resistance: the regulator-approved electricity rate structure drives utilities to want to maximize their sales, which leads to utility opposition to broader implementation of local generation.

Casten gives an overview of recent history. In 1978, PURPA allowed efficient cogenerators to sell to their local distribution utilities at avoided cost. PURPA may have broken the monopoly on generation, but it preserved utilities' monopoly on distribution. In response, utilities set high rates for back-up service to make self-generation less attractive; because cogenerators had no alternative options for back-up distribution service, utilities could force customers to pay this higher price. Likewise, utilities began making the interconnection process more onerous by requiring extensive studies, and by requiring interconnections to be at transmission-level voltages.

We have seen utilities interpose these obstacles. For example, one local distribution company attempted to shift its rate structure to recover more from customers based on their peak demand using a "demand ratchet". Although this reduced the volumetric energy component of the utility's rates, the effect on a customer who had recently installed self-reliant cogeneration was to require that customer to pay nearly the same amount for backup service as it had been paying for full-requirements service. Only through a rate case before the Public Utilities Commission did we push the utility back.

The 1992 Energy Policy Act is Casten's next milepost. EPAct 1992 broadened the right to sell power at wholesale, while eliminating the cogeneration requirement. In the ensuing decade, over 120,000 MW of merchant gas-fired generation was built, and coal and nuclear plants increased their run-time. Meanwhile, many states forced utilities to divest their generation.

Other highlights include:

• US T&D line losses average 9%, and can reach 25% at peak. By contrast, local generation losses might be 2%.
  
• T&D development is expensive, and has a high capital cost. Local generation requires little to no T&D build-out.
• Nearly half of the average 10 cents per kWh customers pay in the US goes to pay for line losses, return on T&D capital, and operations. Local generation incurs none of these costs.

Casten concludes that the US should establish enhanced incentives for clean generation including CHP. Specifically, Casten proposes a federal requirement that utilities develop a clean standard offer which includes distribution costs. Casten estimates that this would result in a 15% decrease in rates paid by consumers.

Casten also dips into climate change issues. He proposes an "output-based pollution allowance system", under which a decreasing number of allowances are allocated to generators to be credited against MWh generation and Btu conversion.

Personally, I see CHP as a significant opportunity for the future. I'd even consider installing CHP units in new residential construction. Particularly once the installed price goes down, we can achieve both environmental and financial goals through efficient cogeneration.