Vermont dam weathers Hurricane Irene

Hurricane Irene barreled up the East Coast of the U.S. this weekend, bringing high winds and heavy rain to a broad swath of the continent.  About 5 million electricity customers lost power at some point during the storm's progress, with service still off for many consumers.  Hurricanes and other storm events place added stresses on our electric infrastructure, resulting in not only power outages but possible dam failure.

In rain-lashed Vermont, utility Green Mountain Power worked to prevent the failure of the Marshfield Dam near the town of Cabot.  Located on the Winooski River less than 20 miles upstream from Vermont's capital Montpelier, the earthen Marshfield Dam creates a 400-acre impoundment known as Molly's Falls Pond.  Green Mountain Power uses the water impounded by the dam to run a 5-megawatt hydroelectric project.


Irene dumped a lot of water on Vermont.  As a result, the water behind the Marshfield Dam rose within 10 feet of the dam's crest on Sunday night -- far too close for comfort.  When the impoundment behind any dam gets too full, the dam is at increased risk of breaching; if a dam gets overtopped -- particularly an earthen dam -- this risk of dam failure is even greater.  Dam failure at Marshfield could have serious impacts for the people and property downstream in the Winooski River Valley, from Montpelier further down.  As a result, Green Mountain Power's emergency plan calls for a large controlled release of water through the dam once the water gets within 6.5 feet of the dam's crest.  As a precaution, the utility asked the state emergency management agency to evacuate about 300 households in Marshfield, Plainfield, East Montpelier and Montpelier.  Dam safety was at risk.

In the end, the water stopped rising, and then returned to a lower level.  (Check out the USGS's streamflow data for the Winooski River near Montpelier.)  Although Vermont suffered major damage from Hurricane Irene's remnants, the Marshfield Dam survived this storm.

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.

Massachusetts may revamp solar and distributed generation interconnection process

Being able to interconnecting electricity generating units to the grid is almost always necessary.  Even islands - literal or figurative - often have their own microgrids to which new generation must be interconnected, but usually the electric grid in question is run by a public utility.

Despite federal and state policies designed to promote the development of solar energy projects and other renewable and efficient distributed generation, many utilities are failing to process interconnection applications within the timelines required by their tariffs.  (As I previously wrote, regulators in the Canadian province of Ontario are currently wrestling with this problem as well.)  A recent filing by the energy office of the Commonwealth of Massachusetts appears likely to trigger reforms to the process for interconnecting new distributed generation to the grid.

The Massachusetts Department of Energy Resources’s filing consists of a consultant's report commissioned by DOER and the Massachusetts Clean Energy Center, coupled with a formal petition requesting that the Department of Public Utilities open an investigation on interconnection procedures.

Prepared by consulting firm KEMA, the report provides a snapshot of the current interconnection process, as well as offering recommendations for improvements.  The report is based on surveys of distributed generation developers and utilities.  The report’s key findings include:

• Significant Increase in New Distributed Generation:  Recent years have brought a significant increase in the volume of applications for interconnection of distributed generation in Massachusetts.  The volume of interconnection applications reviewed grew by a factor of 7 between 2004 and 2010 - a significant increase in interconnection requests.
• Current Process Can't Handle the Volume:  A very high percentage of utility reviews of interconnection requests have missed key deadlines.  For example, in 2009, 100% of the interconnection application review conducted under utilities’ standard process exceeded the timeline specified in the utility’s tariffs.  Currently, utilities face no penalty for missing these deadlines.  As the report notes, “There is no consequence to the utilities for delays, even though there are consequences – often significant – to the DG applicants.”
• Interconnection Costs Cause Frustration:  While current application fees and witness test costs may be reasonable, the report notes that applicants are generally dissatisfied with the costs of the interconnection facilities upgrades and equipment required by utilities.  Disputes over the nature and cost of new and upgraded facilities increase costs, add delays, and further chill distributed generation development through increased uncertainty.

The report notes that these failings come despite significant policy support for distributed generation:

In summary, the meta-message of this report rests at the intersection of several trends.  Massachusetts has created a vibrant policy environment for DG, underpinned by one of the best interconnection processes in the country, a process which has generally worked well for most DG applicants since its introduction in 2004. Over the last seven years, however, and particularly under the Patrick Administration, the growth in DG volume has grown significantly.

Yet, our survey showed that 79% of Expedited applicants and 75% of Standard applicants are “Somewhat dissatisfied” or “Very dissatisfied” with a process they describe as long, inconsistent, and “too complicated to comment”. . . .

We define a successful process as one that meets its customer demand with high quality outcomes, within acceptable parameters of time and cost. This review demonstrates that – seven years after its introduction – the current process by which DG is interconnected in Massachusetts is no longer meeting the demands of three-quarters of its customers.

Based on these findings, the report offers recommendations to remedy the system's failure, including proceedings before the State Department of Public Utilities to redesign the interconnection process to be better suited to high-volume penetration of distributed generation.

The DOER’s petition was filed on August 18, 2011.  The Department of Public Utilities is expected to respond to the petition by opening an investigation on interconnection along the lines suggested in the report.  How that proceeding affects the experiences of utilities, distributed generation owners or developers, and ratepayers remains to be seen.

Maine's offshore wind test sites

Within the next several years, three sites off the coast of Maine may see offshore wind tests and pilot projects.  In December 2009, the Maine Ocean Energy Task Force selected three sites -- waters near the island of Monhegan, Boon Island and Damariscove Island -- as test sites for offshore wind development.

Looking northeast from Griffith Head, Reid State Park, Maine.

Plans to develop these sites remain pending.

The Monhegan site (PDF map) lies about 2 miles south of the island, and runs about 2 miles square near the edge of Maine's state territorial waters.  At the Monhegan site, the DeepCWind Consortium, a group led by the University of Maine, plans to develop a scale-model floating platform and test turbine about 2 miles south of the island.

The Damariscove site (PDF map) lies southwest of uninhabited Damariscove Island, about halfway between Damariscove and Seguin Island off the mouth of the Kennebec River.

The Boon Island site (PDF map) lies about 2 miles south of that island, off the town of York on the southern coast near Kennebunkport.

What will the coming years bring to these sites?  The Monhegan site may see its first floating turbine deployed in 2012.

Blythe shifts from concentrating solar to PV

One of the world's largest solar projects may partially shift from concentrating solar thermal to photovoltaic technology.  If it happens, this technological shift demonstrates how different technologies compete for market share even within a given project.

Over the past year, I've written several times about the Blythe solar energy project under development in California.  Proposed by Solar Trust of America, a joint venture between German developers Solar Millenium AG and Ferrostaal AG, the full-scale project could add about 1,000 megawatts of new solar capacity to the regional grid -- about as much capacity as a nuclear plant, although less capable of producing that full value around the clock.  As originally proposed, the Blythe project would rely on mirrors to concentrate the sun's rays to heat water, making steam to run turbine generators.

Solar Millenium has now announced plans to convert the first 500 MW phase of the Blythe project to solar photovoltaics.  With this decision, the Blythe project is now on track to follow nearly 1,850 MW more California solar capacity changing from solar thermal to solar PV in just the last year.  Observers note that this shift is spurred in part by lower photovoltaic costs as a result of greater market penetration, with solar panel elements falling nearly 50% in cost in recent months.

The Blythe developers have not yet selected a PV panel manufacturer, nor have they specified the technology for a second 500 MW phase of the project.

Massachusetts regulators approve utility's wind contracts

In most U.S. states, laws require utilities to include a specified amount of renewable power in the energy mix they sell customers.  These renewable portfolio standard (or RPS ) laws vary from state to state in their details, but vertically-integrated can often satisfy the RPS by entering into contracts to buy power from specific renewable projects.  For example, Massachusetts' largest utility National Grid plans to buy half of the Cape Wind offshore wind project's output to comply with the RPS.

On Friday, Massachusetts regulators approved an array of wind energy contracts proposed by the Commonwealth's second-largest utility, NStar.  The state Department of Public Utilities has been considering contracts between NStar and three wind projects:

• Iberdrola's 29 megawatt Hoosac Wind project, in the Berkshires of Massachusetts, should be running July 2012, a ten-year deal
• Iberdrola's 48 megwatt Groton Wind project near Plymouth, New Hampshire, should be running December 2012, a ten-year deal
• First Wind's 32 megawatt Blue Sky East project in Eastbrook, Maine, should be running by May 2012, a fifteen-year deal

While the agreements' pricing remains confidential, some aspects of the pricing are known.  NStar conducted a competitive bidding process to select the projects for contracting; NStar's process is said to have emphasized getting the lowest price.  It is also public that the three contracts approved on Friday are for fixed prices, meaning that unlike escalating price contracts, the price the utility pays the wind developers per kilowatt-hour will remain flat over the contracts' terms.

August 18, 2011 - new report assesses Texas, SW blackouts

Last February’s blackouts in Texas and the Southwest disrupted life for millions of electricity consumers.  When the weather became unusually cold for the region and an ice storm struck, a number of electric generators suffered outages, and natural gas supplies became curtailed.  As a result, real-time wholesale power prices rose to 40 times their previous level, and grid operators were forced to resort to rolling blackouts.  Even as the grid struggled to maintain its integrity, policymakers called for an investigation of what happened – and how to prevent a repeat performance.

This week, after six months of inquiry, the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corporation (NERC) have released a report on the incident.  This report – linked here as a 357-page PDF – concludes that most of the electric outages and gas shortages were due to weather-related causes, but noted that proactive steps to protect reliability were lacking.

For example, although many generators did in fact winterize their plants so they could operate in cold conditions, the report concludes that no state, regional or NERC standards required generators to take this step.  The report notes that electric outages were generally caused by weather-related mechanical problems that could have been prevented by proper weatherization – measures to prevent frozen sensing lines, equipment, water lines and valves.

The report similarly concludes that the natural gas shortages and outages were mostly attributable to the lengthy cold weather, the resulting and unprecedented high demand for gas, and simultaneous reductions in supply.

Will this report change the way we protect the reliability of our grid?

August 16, 2011 - DOE loan guarantee to Maine wind project

A wind energy developer has just received a $102 million loan guarantee to support its project in Maine.  Yesterday the U.S. Department of Energy lent its financial support to Record Hill Wind LLC for its 50.6 megawatt project near Roxbury, Maine.  The project's design includes 22 Siemens turbines and an 8 mile transmission line to interconnect with Central Maine Power's system.  Born out of a partnership between Independence Wind LLC and Wagner Forest Management, the project also scored major financial support from the Yale University endowment fund.

Record Hill Wind's federal loan guarantee through the DOE further solidifies the project's financial footing.  Department of Energy operates several loan guarantee programs; Record Hill's backstop comes courtesy of DOE's Section 1705 program, which is now ramping down.  While the Section 1705 program may be a casualty of the federal budget, DOE's three loan programs have to date offered over $40 billion in support for 42 clean energy projects across the country. 

August 15, 2011 - Canadian utility versus distributed solar

State and provincial governments are implementing programs designed to promote the growth of small-scale distributed renewable energy projects like solar photovoltaic installations.  For these programs to succeed, new distributed energy projects need to be able to interconnect into the existing utility grid on a fair and predictable timeline.  For this reason, feed-in tariff and other distributed generation programs must work hand-in-hand with utility tariffs requiring fair interconnection access – but some solar and renewable industry groups are concerned that utilities may not be honoring these obligations.

A small solar array serving the Utah Communications Agency Network radio system atop Beaver Mountain, UT.

Consider the example of the Canadian province of Ontario.  The Ontario Power Authority – the entity charged with ensuring an adequate, long-term supply of electricity in Ontario – offers feed-in tariff programs for qualified generation.  Ontario’s “micro-FIT” program gives developers of small renewable power projects – 10 kW or less – long-term contracts to sell the projects’ output at a fixed price.  For rooftop solar projects, these contracts pay 80.2 ¢ per kWh for a 20-year term – about ten times the most recent regulated retail electricity price in Ontario.

As anticipated, this program has drawn interest from thousands of developers of small generating units – perhaps as many as 25,000 by earlier this year.  Each of these projects is entitled to interconnect to the electric grid in a timely fashion, but doing so requires the local utility to evaluate the technical and engineering aspects of the interconnection to ensure safety and system reliability.  For example, a utility must formally offer to interconnect with a project within 15 days if it is at an existing interconnection point, with actual interconnection to be completed within 5 days after the utility receives its customer’s payment and signed agreement.

Some utilities are having trouble complying with this schedule.  In a case currently pending before Ontario’s energy regulator, one utility has asked for a waiver of the interconnection timeline.  Hydro One Networks Inc.’s April 2011 petition to the Ontario Energy Board, docketed as case EB-2011-118, notes that it was in non-compliance on an estimated 442 interconnection applications based on the utility’s failure to meet tariffed deadlines.  As a result, the utility asked to be relieved of its scheduling commitments for six months.

Businesses, homeowners, and the solar installation industry have objected to this request, pointing out that they have already suffered great harm as a result of the utility’s failure to meet its interconnection timing deadlines.  Evidence submitted in the case suggests millions of dollars in lost revenue, layoffs, and business closures as a direct result of the utility’s missed deadlines.

The Ontario Energy Board conducted hearings on the utility’s waiver request, but has not yet issued a ruling.  When it does, it may affect not only people interested in solar energy development but moreover the balance between traditional centralized utility organization and Ontario’s pro-distributed generation feed-in tariff policy.

August 12, 2011 - federal energy efficiency legislation

US energy efficiency may soon take a step forward in the form of federal legislation.  S. 1000, the Energy Savings and Industrial Competitiveness Act of 2011 (link), aims to promote energy savings in residential and commercial buildings and industry.

The bill contains measures designed to tackle various aspects of energy efficiency.  Title I targets buildings, calling for improvements to national model building energy codes and appliance standards.  Title II gives public power districts and electric cooperatives access to a rural energy savings loan fund.  These entities can either use the money themselves at zero interest, or may loan it out to consumers at an interest rate capped at 3%.  Title III tackles industrial energy efficiency, creating a revolving loan program in partnership with states to fund industrial projects.  Title IV covers the federal government itself as an energy consumer, creating programs designed to study and improve federal energy efficiency.

S.1000 has been favorably reported out of the Senate Committee on Energy and Natural Resource, and may move forward later this session.

August 8, 2011 - what's in your electricity supply mix?

What kinds of generation resources make up your electricity supply mix?  While the answers differ across suppliers and over time, the question of what's in your generation basket can affect not only the price you pay for power but also the environmental attributes of the power used to satisfy your demand.

Customers have an interest in understanding which generation resources are in their energy mix.  In states like Maine, electricity suppliers and utilities have been required to provide customers mailings containing information on the resource mix.  By looking at this data over time (like this August 2010 mailing, this November 2010 mailing, and this July 2011 mailing), customers can understand not only what they've been buying but how it is changing over time.

Now, in a notice of proposed rulemaking (26 page PDF), the Maine Public Utilities Commission proposes to repeal its rule requiring competitive electricity providers and transmission and distribution utilities to provide quarterly mailings with supply mix information.  This follows on the heels of a 2011 law change by the Maine State Legislature which opened up more flexibility in how these suppliers must make supply mix information available.

The Maine PUC is entertaining comments on its proposal until September 9, 2011.  Will the new rule require (or allow) suppliers to make supply mix information available in electronic or online formats in lieu of paper mailings?

August 4, 2011 - Northern Pass transmission project delayed

For the past year, several large New England utilities have been collaborating on a major new transmission project to connect Canadian generators with New England markets. Northeast Utilities and NSTARhave proposed a high-voltage DC transmission line they call the "Northern Pass".  If built as proposed, this $1.1 billion transmission line will be capable of sending about 1200 MW of power from Hydro-Quebec's generation network into New England.  Canada, and Quebec in particular, possess many gigawatts of generation capacity, much of which comes from hydroelectricity.

In the meantime, some project opponents have expressed concerns about local siting issues related to the route the line will take through the White Mountain National Forest, other wild lands, and a number of communities.  Between Groveton, NH, and the Canadian border, no transmission rights of way exist today, meaning about 40 miles of new transmission corridor are needed.  Where this line should run has been a contentious issue.  As a result, the developers have expressed a willingness to consider alternative routes.

At the same time, other opponents have observed that if gigawatts of Canadian renewable power are imported into New England to satisfy domestic renewable power mandates, the region will not see the more localized environmental and economic development benefits from the development of renewable power projects in New England.  Many consider these local benefits key to the value of state renewable portfolio standards.

Now, the Northern Pass developers have announced that a rollback of the project's anticipated startup date to allow for a new route north of Groveton.  On the project's journal website, Northern Pass now states that its "expected in-service date has been modified to 2016, with construction expected in the 2014 – 2016 time frame, compared to the initial range of 2013 – 2015".

August 2, 2011 - green pricing programs grow

"Green pricing" energy programs are one way electricity consumers can choose the mix of resources making up their energy supply.  Under these programs, consumers can voluntarily pay for electricity sourced from renewable resources.  Green pricing programs, which often but not always come at a premium over default service, represent a free market solution to the question of who should pay for renewable power, and give customers control over their energy mix.

This is a different approach from renewable portfolio standards, which require utilities to source specified portions of their power from renewables.  These two strategies can work together, as the majority of states now use both RPS and green pricing programs.

The U.S. Energy Information Administration defines green pricing:

Green pricing:  In the case of renewable electricity, green pricing represents a market solution to the various problems associated with regulatory valuation of the nonmarket benefits of renewables. Green pricing programs allow electricity customers to express their willingness to pay for renewable energy development through direct payments on their monthly utility bills.

The EIA's July 2011 report on green pricing and net metering (9 page PDF) shows a record number of customers participating in green pricing programs.  Green pricing programs now exist in every state except Alaska, Hawaii, and New Hampshire, so it is no surprise that EIA's recent report documents an increase in green pricing participation.  EIA's most recent data, which covers 2009, shows a 6% increase in the number of electric industry participants (utilities, competitive suppliers) with customers in green pricing programs.

The number of customers participating in green pricing programs also increased for a third consecutive year to 1,123,778 customers.  This represents a 12% increase in customer participation  -- and yet green pricing has been chosen by less than 0.08% of the nation's total 143,497,0601 electricity customers.

What does the future hold for green pricing?