July 29, 2011 - President Obama promotes vehicle energy efficiency

Friday, July 29, 2011

From the vehicle energy efficiency department: today President Obama announced a new fuel efficiency standard for motor vehicles.  The Corporate Average Fuel Economy or CAFE standard, developed by the Environmental Protection Agency and the Department of Transportation after input from stakeholders, sets a fleet-wide average standard of 54.5 miles per gallon by 2025.  According to the White House, this standard will save consumers money – $8,000 per vehicle – while also reducing greenhouse gas emissions by 6 billion metric tons and and oil consumption by 2.2 million barrels a day by 2025.
This fuel economy standard raises the bar significantly.  Existing fuel economy rules require cars and light-duty trucks to average 35.5 mpg by 2016.
Meeting today’s stepped-up fuel efficiency standards may not be easy for auto manufacturers, so it is notable that the standard has won the support of leading vehicle makers.  Two compromises may have won automakers over.
First, while 54.5 mpg is significantly higher than the current CAFE standard, it is nevertheless lower than either the 60 mpg promoted by environmental groups or the 56.2 mpg initially proposed by the administration.
Second, the agreement includes incentives and credits for advanced vehicles and technologies that reduce emissions.  EPA and the National Highway Traffic Safety Administration are considering incentive programs for market-changing technologies such as plug-in hybrid electric vehicles, fuel cell-based vehicles, and compressed natural gas (CNG) vehicles.

July 28, 2011 - Vermont's largest solar array compared to California's

Thursday, July 28, 2011

Solar energy projects come in a variety of shapes and sizes: photovoltaic (PV) or thermal, large or small.  A look at Vermont's new largest solar project, and how it compares to the largest solar project in the US under development in California, highlights the range of solar power projects.

Yesterday, Vermont Governor Peter Shumlin officially activated a 2.2-megawatt solar photovoltaic system in South Burlington, Vermont.  Located on a 25 acre site amidst farmland on the fringes of Burlington's metro area, the $12 million project owned by Chittenden County Solar Partners is projected to produce 2.91 million kWh annually.  This output will be sold to Vermont's Sustainably Priced Energy Development (SPEED) Program under a 25-year power purchase agreement.  This PPA, made possible by Vermont's standard offer law, lets sell the solar project sell its output to Vermont utilities at a guaranteed price set by state regulators: in this case, 30 cents per kilowatt-hour.  This is about twice the average retail price for all electricity sold to residential users in Vermont.  Developers note that long-term contracts with guaranteed pricing are often necessary in order to finance projects.  While the Vermont Public Service Board has since lowered the standard offer to 24 cents, the South Burlington project's contract guarantees it the contract price.

Meanwhile, the largest solar project under construction may be the Blythe Solar Power Project in Southern California.  When the project is complete at 968 MW, this solar thermal power station will dward the scale of a distributed photovoltaic project like AllEarth's in Vermont.

What these two projects have in common is that they will both operate by capturing usable energy from the sun.  Both are new, meaning there are jobs involved in designing, constructing, and operating them.  Both can be expected to displace fossil fuel-fired generation, and qualify as renewable under federal and state policy.

The differences are perhaps more striking.  The Blythe project is a massive centralized project, while one of the key features of the Vermont project is its distributed nature.  Not only can distributed generation projects avoid the need to build new large transmission lines just to get the project's power to market -- a significant issue for centralized projects like those in California -- but distributed generation can even enhance the strength of the existing grid by shoring up voltages and reducing line losses.  Combined with the different technologies involved and the different overall project scales, these two solar energy projects illustrate the broad range of projects falling under the solar power umbrella.

July 27, 2011 - why FERC issued Order No. 1000, and what it means

Wednesday, July 27, 2011

I've been covering FERC Order 1000, a landmark regulatory decision that will reshape the U.S. electric grid.

To understand what FERC's Order No. 1000 means for the U.S. transmission system, you need to understand the direction in which the electric industry is changing.  A shift in the generation mix coupled with a sharp uptick in transmission line construction are largely responsible for the need for reforms.

Utility investment in transmission lines is booming.  For example, utility members of the Edison Electric Institute reported $55.3 billion in new transmission facility investment, while another report commissioned by EEI suggests about $298 billion in new transmission facility needs between 2010 and 2030.  In the next five years, new transmission line mileage will be built at a rate nearly three times higher than the historical average.

Why is so much new transmission line being built?  FERC points to changes in the generation mix.  Between air emissions regulation, state renewable portfolio standards, and fuel costs, the mix of energy resources used to generate electricity is shifting.  An increasing reliance on natural gas and large-scale integration of renewable generation means new transmission lines are needed to connect these new generators to markets.  Meanwhile, while coal-fired generation continues to be significant, some facilities like the Salem Harbor Power Station are being retired.  The existing electric grid was not built to accommodate these shifts in the energy mix.

With so much transmission line development underway, the stakes are high.  How lines are planned affects whether society finds the least-cost solution to our electric needs.  How the costs of new transmission lines are split affects whether users of the electric grid -- including both consumers and generators -- get fair treatment.  In issuing Order No. 1000, FERC concluded that the status quo can lead to inefficient and higher-cost decisions being made:
We conclude that the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities, and that addressing these issues is necessary to ensure just and reasonable rates.
Order No. 1000 aims to fix these shortcomings through new requirements on the transmission planning and cost allocation processes.

July 26, 2011 - how FERC Order No. 1000 affects the US electric grid

Tuesday, July 26, 2011

FERC Order No. 1000 reforms how public utilities plan and pay for transmission upgrades.  The 620-page order and final rule, issued on July 21, 2011, is designed to move our electric grid toward a more efficient and cost-effective system -- part of the smart grid movement.

Order No. 1000 (620-page PDF) covers both transmission planning and cost allocation, at both the regional and interregional level.  As FERC notes in the order, under current transmission law, utilities can engage in local transmission planning without having to consider whether regional solutions would be more efficient or cost effective.  Likewise, regional grid operators have been able to approve transmission projects without being required to consider whether an interregional solution -- like connecting New England's electric grid to that of a neighboring region -- would be more efficient or cost effective.  Once a transmission line is approved, the status quo allows grid operators fairly broad discretion in determining who should pay for the line -- all regional consumers, the subset of consumers benefited by the line, generators, or others.  As a result, consumers may be paying more for transmission than they should, while a lack of transmission expansion in certain areas may be stifling the development of renewable power projects.

To fix this problem -- or in the language spoken by FERC as framed by the Federal Power Act, to "ensure that the rates, terms and conditions of service provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential" -- FERC issued Order No. 1000 with two primary objectives:

(1) ensure that transmission planning processes at the regional level consider and evaluate, on a non-discriminatory basis, possible transmission alternatives and produce a transmission plan that can meet transmission needs more efficiently and cost-effectively; and

(2) ensure that the costs of transmission solutions chosen to meet regional transmission needs are allocated fairly to those who receive benefits from them.

Expanding this reform of regional transmission development, Order No. 1000 places a similar framework around interregional transmission planning and cost allocation.

Order No. 1000 will become effective 60 days after the final rule is published in the Federal Register.

July 25, 2011 - FERC reforms transmission policy through Order No. 1000

Monday, July 25, 2011

How should we plan transmission line upgrades to our power grid -- and who should pay for the upgrades?  A new landmark ruling issued by the U.S. Federal Energy Regulatory Commission reshapes the answers to those questions.

Issued on July 21, 2011, FERC Order No. 1000 (620-page PDF) is a sweeping reform of regional and interregional transmission planning and cost allocation.  Previously, each of the many regional grid operators in the country planned transmission upgrades -- and allocated the costs of those transmission projects -- according to its own rules.  Through Order No. 1000, FERC moved the nation toward a standardized planning and cost allocation process by establishing six principles for future transmission cost allocation:

(1) The cost of transmission facilities must be allocated to those within the transmission planning region that benefit from those facilities in a manner that is at least roughly commensurate with estimated benefits.  In determining the beneficiaries of transmission facilities, a regional transmission planning process may consider benefits including, but not limited to, the extent to which transmission facilities, individually or in the aggregate, provide for maintaining reliability and sharing reserves, production cost savings and congestion relief, and/or meeting public policy requirements established by state or federal laws or regulations that may drive transmission needs.

(2) Those that receive no benefit from transmission facilities, either at present or in a likely future scenario, must not be involuntarily allocated the costs of those facilities.

(3) If a benefit to cost threshold is used to determine which facilities have sufficient net benefits to be included in a regional transmission plan for the purpose of cost allocation, it must not be so high that facilities with significant positive net benefits are excluded from cost allocation. A transmission planning region or public utility transmission provider may want to choose such a threshold to account for uncertainty in the calculation of benefits and costs. If adopted, such a threshold may not include a ratio of benefits to costs that exceeds 1.25 unless the transmission planning region or public utility transmission provider justifies and the Commission approves a greater ratio.

(4) The allocation method for the cost of a regional facility must allocate costs solely within that transmission planning region unless another entity outside the region or another transmission planning region voluntarily agrees to assume a portion of those costs. However, the transmission planning process in the original region must identify consequences for other transmission planning regions, such as upgrades that may be required in another region and, if there is an agreement for the original region to bear costs associated with such upgrades, then the original region’s cost allocation method or methods must include provisions for allocating the costs of the upgrades among the entities in the original region.

(5) The cost allocation method and data requirements for determining benefits and identifying beneficiaries for a transmission facility must be transparent with adequate documentation to allow a stakeholder to determine how they were applied to a proposed transmission facility.

(6) A transmission planning region may choose to use a different cost allocation method for different types of transmission facilities in the regional plan, such as transmission facilities needed for reliability, congestion relief, or to achieve public policy requirements established by state or federal laws or regulations. Each cost allocation method must be set out clearly and explained in detail in the compliance filing for this Final Rule.

July 22, 2011 - Nova Scotia tidal energy: past, proposed, and future

Friday, July 22, 2011

This week's story about a possible hydrokinetic tidal energy project in Nova Scotia's Bay of Fundy reminded me of large-scale tidal projects that have been proposed in northeastern North America over the years.  Chief among these may be the Passamaquoddy Power Project proposed in the early 20th century, but the PPP wasn't the only grand project dreamed up.

Sunset over the harbor at Five Islands, Georgetown, Maine.

One tidal project floated in the early 1980s involved developing up to 6,000 MW of tidal power capacity through two dams in Nova Scotia.  One dam would have blocked off Shepody Bay (the arm of the Bay of Fundy reaching toward Moncton and the Petitcodiac River near the Nova Scotia - New Brunswick border), while the other would have walled off part of Minas Basin between Cape Blomidon and Parrsboro.  Neither of these dams was ever built, although the tidal energy resource of Minas Basin continues to draw interest.

One reason may be the impact of the projects on coastal communities along the Bay of Fundy -- and in fact well out into the Gulf of Maine.  A news article from 1981 suggests that these tidal dams would have increased the tidal range in Portland, Maine -- about 300 miles away -- by up to 18 inches.  This increase in tidal range could have negatively impacted coastal communities, eroding soil, causing property damage, and tidal flooding.  By contrast, the article suggested that the Passamaquoddy project or a smaller one proposed for Half Moon Cove would not raise tides elsewhere.

These projects may not have been built, but with Nova Scotia's new community-based feed-in tariff, developers of in-stream tidal projects can expect $652 per MWh for qualified energy produced in the province.  Will Nova Scotia's feed-in tariff lead to more tidal projects in the Bay of Fundy?

July 21, 2011 - how the electricity supply mix affects air emissions

Thursday, July 21, 2011

The types of generators making up your electricity supply mix vary from region to region and time to time.  How that mix is composed affects the air emissions associated with the electric power sector.

Yesterday, I looked at a mailing I recently received about the resources making up my electricity supply.  Also included in that fact sheet was this chart showing the average air emissions of carbon dioxide (CO2), nitrogen oxide (NOx), and sulfur dioxide (SO2) in pounds of emissions per megawatt-hour of power sold to customers:

The power sold through this standard offer period averaged 605.86 pounds of CO2 per MWh generated -- 34.5% less than the New England system average over the same time.  NOx and SO2 emissions were 0.52 and 0.94 lbs per MWh respectively -- each about half the emissions rate per MWh of the regional average.

July 20, 2011 - my energy supply mix

Wednesday, July 20, 2011

Today, a quick update on Maine's energy mix.  (For previous snapshots of the generation resources supplying, check out this post from November 2010 and this post from August 2010.)

Here's a recent mailing I received at my house detailing the power source mix for the standard offer provider for customers of Central Maine Power's network: NextEra Energy Power Marketing, LLC.

On a volumetric basis, hydroelectricity accounted for the greatest share of energy sold: 30.1% of the power served through this standard offer period.  Natural gas-fired generation came in a close second, with 29.8% of the supply.  Nuclear power rounds out the major players in this supply mix, at 22.4%.  These three resources alone produced 82.3% of the power sold through this standard offer.

How much of this power is renewable?  Hydroelectric generation is considered renewable.  Maine law requires suppliers to source at least 30% of their power from existing renewable resources like hydropower -- which correlates very closely to the 30.1% actually sourced from hydropower here.  Maine's renewable portfolio standard also requires utilities to source an increasing percentage of their power from new renewable projects built or refurbished in recent years; in 2010, that requirement amounted to 3% of load served.  Assuming that the facilities in question qualify as new, this supplier appears to have met that requirement with biomass (1.8% of load served) and wind (1.6%) of load served.

Which generation resources make up your energy mix affects both the price of electricity and its environmental attributes such as air emissions.  Tomorrow, I'll look at the air emissions associated with this energy mix.

July 19, 2011 - Nova Scotia tidal energy, feed-in tariffs and projects

Tuesday, July 19, 2011

Hydrokinetic energy projects are cropping up in Canada just as they are in the U.S.  (For a review of hydrokinetic energy, check out last month's entries.) The Bay of Fundy is famous for its tides, among the largest in the world.  The Canadian province of Nova Scotia is home to a large portion of this resource.  Nova Scotia is also home to an existing tidal power plant: utility Nova Scotia Power's Annapolis Tidal Power Plant.  This tidal energy project, which came online in 1984, has a capacity of 20 megawatts and can generally produce between 80 and 100 megawatt-hours per day.

The tide drops out of a tidal marsh near the Back River on Arrowsic Island, Maine.

Now, Maine-based Ocean Renewable Power Co. has announced plans with Nova Scotia-based Fundy Tidal Inc. to install underwater hydrokinetic turbines to generate electricity from the Bay of Fundy's tides.  The proposal involves the installation of 15 to 20 150-kW turbines in the Petit Passage between Digby Neck and Long Island off western Nova Scotia (map) by 2012. 

The new venture, named ORPC Nova Scotia Ltd., plans to benefit from Nova Scotia's feed-in tariff.  That program, known as the community-based feed-in tariff or COMFIT, is projected to require utilities to pay qualified tidal projects 65.2 cents per kilowatt-hour for their output.  This rate, about six times higher than the typical rate for electricity, is a significant incentive for the development of the province's resources.  Additional support is available from the provincial government to assess hydrokinetic and small tidal projects like the Petit Passage project.

This project may be smaller than the 500 MW Passamaquoddy Power Project first proposed in 1919, but it could represent the first commercial deployment of underwater hydrokinetic turbines in the Bay of Fundy, and follows in Nova Scotia's traditions of harvesting the energy of its tides.

July 15, 2011 - will Maine have a new largest dam?

Friday, July 15, 2011

Since 1954, Maine's largest-capacity hydroelectric dam has been the 85 megawatt Harris Dam on the Kennebec River - but it may soon lose its title to another project on the same river.

Water spills over the last falls on the Cathance River in Topsham, Maine.  These falls powered a sawmill as early as 1716.

Harris Dam may soon lose its title as Maine's largest dam -- but not because a new dam is being built.  Rather, dam owner FPL Energy Maine Hydro LLC -- a subsidiary of NextEra Energy Resources -- has embarked on a program to improve the efficiency of the three turbines at Wyman Dam, the next dam downstream from Harris.

Wyman Dam, currently rated at 83 megawatts capacity, was built in 1930, 24 years before the Harris Dam.  Improvements to two of the three Wyman turbine generators have already occurred, and NextEra now proposes to complete the project.

Between the recent efficiency upgrades and a closer look at older improvements, NextEra now thinks the overall licensed project capacity should increase from 83,700 kW to 88,010 kW, an increase of 4,310 kW.  NextEra has applied to the Federal Energy Regulatory Commission for a license amendment to reflect these upgrades.

Comments on this proposal are due by August 5, 2011.  If approved, Wyman Dam's newly-tallied 88 megawatts of capacity will slip past Harris Dam's 85 MW to become Maine's largest hydroelectric dam.

July 14, 2011 - Maine tidal power navigates the regulatory process

Thursday, July 14, 2011

Can tidal power produce electricity for a Maine island?

Sunset over skiffs tied up at Five Islands in Georgetown, Maine.

Developer TideWorks LLC apparently thinks so.  In January 2010, Tideworks filed an application to the Federal Energy Regulatory Commission for a 5 kilowatt project to be sited in the Sasanoa River, off the east side of the island town of Georgetown near Bath.  This small project was proposed to provide power to a single-family dwelling on 15-acre Bareneck Island.  Tideworks initially applied to FERC for an exemption from licensing.  In its application, Tideworks described the project as including a single vertical shaft turbine-style generator housed on a 10' x 20' steel pontoon float held parallel to the east side of Bareneck Island using 40' steel struts.  The Bareneck Island house is currently tied to the mainland grid by a 7,200 volt submarine cable, stepped down to 220 volts by a transformer on the island.  While Tideworks proposed to keep this underwater cable connection "unless or until the applicant feels the proposed turbine unit will sustain the power needs of the dwelling", its application noted that the power generated by the turbine will be utilized to power the existing residence.

Beyond the technical challenges of building the project, this Maine tidal project must now navigate the regulatory process. Throughout 2010, agencies like NOAA's National Marine Fisheries Service and the U.S. Department of Commerce filed cautious comments with federal regulator FERC.  After requesting more information from the developer, FERC accepted Tideworks' exemption application for processing and solicited comments.  By September, FERC deemed the application ready for environmental analysis.

As agencies reviewed the project, the U.S. Department of the Interior and Maine Department of Marine Resources used their authority under Section 30(c) of the Federal Power Act to require Tideworks to screen the turbine to prevent fish from being killed.  Specifically, the agencies requested a screen with openings of 1 inch or less, and an approach velocity of two feet per second or less at the screen to allow fish to swim away from the intake.  These measures are used to protect fishery resources at conventional riverine hydropower projects, and the agencies urged the use of this standard given the unknown effects of the proposed hydrokinetic turbine unit on fishery resources.  However, this slow approach velocity was below the minimum operating velocity of the turbine, significantly challenging the project's design.   As Tideworks later described the standoff in a filing to FERC,  "the  project will not be able to generate/operate as a result of these two agency 30(c) conditions (screening/approach velocity)".

Additionally, the developer was encouraged to choose a different regulatory path.  Rather than FERC's traditional licensing process, the project appeared to qualify for a more streamlined licensing process for hydrokinetic pilot projects. By March 2011, Tideworks filed an amendment to its application, dropping the request for an exemption from licensing and instead seeking a hydrokinetic pilot license.  FERC noted that the same environmental protections, including the problematic screening, would likely apply to a hydrokinetic pilot license as well, and asked the developer to work with key agencies to identify any other project restrictions.

Last week, FERC again asked the developer for more information.  In a letter, FERC reminded Tideworks of the commission's hydrokinetic pilot project licensing procedures, including the need to file specific documents including a draft license application and notice of intent.

The hydrokinetic project licensing process is new enough that it is hard to call any one project "typical", but the Tideworks project on the Sasanoa River in Maine illustrates the process of developing an island tidal power resource.

July 13, 2011 - US Senate considers hydrokinetic energy

Wednesday, July 13, 2011

Hydrokinetic energy -- generating electricity from tides, waves, and free-flowing rivers -- is drawing significant interest in 2011, with about 200 project sites far enough along to seek key federal regulatory approvals.  (For a look at the range of those projects, check out my previous blog entries on hydrokinetic energy.)

Hydrokinetic power in the US may soon get another boost, as the Senate is considering a bill to facilitate hydrokinetic projects.  Senator Murkowski of Alaska has sponsored S.630, also known as the Marine and Hydrokinetic Renewable Energy Promotion Act of 2011.  (You can find the text of the bill here.)

As drafted, the bill includes a Congressional finding that
      (1) the use of marine and hydrokinetic renewable energy technologies can reduce contributions to global warming;
      (2) marine and hydrokinetic renewable energy technologies can be produced domestically;
      (3) marine and hydrokinetic renewable energy is a nascent industry; and
      (4) the United States must work to promote new renewable energy technologies that reduce contributions to global warming gases and improve domestic energy production.
Based on these findings, S.630 goes on to provide a variety of support for hydrokinetic projects.  These include the creation of a competitive grant program for marine and hydrokinetic renewable energy technology research, development, and demonstration, as well as another grant program to help commercialize marine and hydrokinetic renewable energy.  Under current law (42 U.S.C. 17282), the US Department of Energy can award grants to support the construction of small hydropower facilities (15 megawatt capacity or less). While this incentive is currently limited to projects in Alaska, S.630 proposes to open it up to projects located anywhere in the country.  The current draft of S.630 includes funding through fiscal year 2014 for these programs.

The future of hydrokinetic energy in the US hinges on a number of variables.  How will S.630 be changed as it moves through Congress?  Will it be enacted into law?  How will new technologies change hydrokinetic project economics?  Depending on the answers to these questions, hydrokinetic projects may soon be helping us keep the lights on.

July 11, 2011 - electricity on Maine's islands

Monday, July 11, 2011

For people summering or living on Maine's islands, getting electricity can be more complicated than on the mainland.  Some of Maine's largest and most populous islands like Mount Desert Island or Deer Isle are connected to mainland by both bridges and electricity cables, while more remote islands are powered by small on-island generators.  By their nature, islands can make energy questions more challenging, while also offering innovative opportunities for the right places.

The summits of Mount Desert Island loom large over the water on Great Cranberry Island, Maine.

Looking at the Maine island communities I identified last week, a number of them are part of mainland utility Central Maine Power Company's service territory.  The major Casco Bay islands -- Peaks, Great Diamond, Cliff, Long, and Great Chebeague -- all fall into this category, as does Islesboro off Lincolnville.  Residents on these islands draw their electricity from CMP's mainland grid via underwater cables; generally, they pay the same price for their electricity (both the supply of energy and the delivery service via the transmission and distribution utility) as do mainland consumers.  The Cranberry Isles off Mount Desert Island are similarly connected to Bangor Hydro-Electric's mainland distribution system at mainland prices.

Other island communities have their own utilities or districts, but remain tied to the mainland by cables.  For example, Vinalhaven and North Haven residents get their power from the Fox Islands Electric Cooperative.  These communities are connected to the mainland grid via underwater cable; until recently, they purchased power from the mainland market at 9-10 cents per kilowatt-hour, on top of which they paid transmission and distribution costs.  In 2007, those wires charges were 16.8 cents per kWh.  The subsequent development of Vinalhaven's 4.5 megawatt community-owned wind project means that Fox Islands residents now pay 27% less for their energy.

Still other island communities are so remote that they are truly islands in the electric sense: completely off the mainland grid.  Electricity on these islands tends to be expensive.  For example, the Maine Public Utilities Commission reports that on Monhegan, the average cost of energy plus delivery has been as high as 62 ¢/kWh.  These high prices are mirrored on other remote islands like Matinicus (47 ¢/kWh) and Isle au Haut (32 ¢/kWh).  With electricity prices like these on Maine islands, it is no wonder that residents consider energy efficiency and other options for using energy more wisely.

July 6, 2011 - Maine's island communities

Wednesday, July 6, 2011

Maine's rocky coast is home to thousands of islands -- 3,166 of which have been listed on the Maine Coastal Island Registry.  Many of these islands are very small -- some mere ledges sticking up above the mean high tide mark -- while others sport communities of year-round residents.  Island living offers a unique lifestyle, while posing challenges to residents: how do you get drinking water?  What energy resources do you use for lighting and heating?  What will it take to make living and doing business on the islands economically viable?

Uninhabited Duck Islands beyond a strip of the Cranberry Isles, Frenchman's Bay, Maine.

The answers to these questions depend on the wheres and whats of each island.  Some islands are tied to other islands or the mainland through pipes, cables, and even bridges.  Other islands are owned by one landowner, are undeveloped, or are more remote and pose different challenges.  Some islands may have cost-effective ocean energy resources just beyond their shores, opening the door to a whole new realm of opportunity for islanders.

The Island Institute identifies fifteen year-round island communities off the Maine coast, sorted into three geographic regions.  Five year-round communities lie within Casco Bay.  Peaks, Great Diamond, and Cliff Islands are all part of the city of Portland.  Long Island seceded from Portland in 1993 and now forms its own town.  Great Chebeague was a part of the town of Cumberland until 2007, when it seceded and became the town of Chebeague Island.  Of these, Peaks is the largest island with over 800 permanent residents, and a summer population that may rise as high as 6,000.

Six island communities fall within Penobscot Bay.  Vinalhaven and North Haven are the largest, with over 1200 people on Vinalhaven and over 300 on North Haven.  Many more people come for the summer.  Isle au Haut is home to about 80 people, and is mostly part of Acadia National Park.  Islesboro has over 600 residents, Monhegan about 75, and Matinicus about 50.

The remaining four communities lie farther downeast, clustered south of Mount Desert Island.  Swan's Island has about 300 people; Great Cranberry about 40 year-rounders and about 300 summer residents; Islesford, or Little Cranberry, has more permanent residents despite its smaller size.  Long Island (not the one in Casco Bay) is home to the village of Frenchboro.

Beyond this list, hundreds of other islands have structures on them where people live at least part of the year, and people do winter over on islands outside of these fifteen communities.

Some of these -- mostly the more populous islands closer to shore -- are connected to the mainland electric grid by underwater distribution cables.  For example, Great Cranberry Island is connected to Manset on mainland-tied Mount Desert Island by an underwater line owned by Bangor Hydro.  Waves during a winter storm in February 2009 caused the line to suffer an outage.  Great Cranberry and neighboring Islesford lost power.  In that case, the utility provided a temporary repair within hours, and installed temporary generation to cover the islands' load while a more permanent fix could be made.

July 5, 2011 - ambitious Mississippi River hydrokinetic projects up close

Tuesday, July 5, 2011

Staking a claim to a site for a hydrokinetic energy project can feel a bit like the wild West.  A recent flap over rights to study and seek licenses for hydrokinetic projects in the lower Mississippi River illustrates the challenges of the race to get a permit, and the changing ways in which regulators evaluate permit applications.

A weathered boathouse on the rocky shore of Islesford, Maine.

I've already noted the significant interest in developing the hydrokinetic resources of the lower Mississippi River.  Developers have filed about 300 preliminary permit applications for Mississippi River hydrokinetic projects, with two developers -- Free Flow Power Corporation and Northland Power -- applying for the vast bulk of the sites.  As of April 2011, Free Flow Power had 24 active permits for the Mississippi River, with applications filed for another 105 river sites.  Northland has applied to the Federal Energy Regulatory Commission for preliminary permits at 40 sites along the same reach, 28 of which Free Flow Power is also pursuing.

This flood of interest in preliminary permits for hydrokinetic projects in the Mississippi River appears to have taken federal regulators by surprise.  Between the applications filed by these two developers, preliminary permits have been sought or awarded for 141 sites covering nearly all of this 850-mile reach of the Mississippi River.  On April 1, 2011, the director of FERC's Office of Energy Projects sent a letter to these two developers, expressing skepticism that two companies could actually develop and file license applications for more than a small fraction of the sites during the short term of the preliminary permit.  (Recall that a preliminary permit just stakes a temporary claim to a site; to build and operate a project, a full project license is generally required.)  The director's letter also expressed concern over letting two applicants tie up so much of the river.  Based on these concerns, the letter noted that Commission staff intended "to decline to issue additional permits on this stretch of the river, and instead allow potential developers to advance their projects through the Commission’s licensing process."

In response, Northland Power pointed out that a Commission policy to deny permits would prevent Northland from studying the sites enough to know if it wanted to file a license application, let alone from promoting competition and developers' reasonable rights to reserve sites.  Free Flow Power noted that the timing and standards of the Commission's Integrated Licensing Process make it "impossible" to file a complete license application within the 3-year term of a preliminary permit.  As a concession to FERC's interest in competition, Free Flow Power also trimmed back its request for permits, withdrawing 58 of the 60 new preliminary permit applications for the Mississippi (representing 419 river miles) and choosing not to seek successive permits for a handful of sites whose preliminary permits had expired. 

This twin-pronged message  -- supporting competition and offering compromise  -- apparently worked.  In letters to the developers dated June 9, 2011, FERC staff noted, "After reviewing all of the resulting filings, staff has determined that it is appropriate to continue processing permit applications on the lower Mississippi River at this time."  

(FERC accepted for processing 43 of Free Flow Power's applications for permits, and incidentally told Northland Power that 40 of its permit applications were deficient for failing to include geographic information about the project and adjacent communities, requesting additional information within 30 days.  As of July 4, 2011, FERC's eLibrary system did not yet show any follow-up from the developer.)

July 1, 2011 - hydrokinetic projects in Maine

Friday, July 1, 2011

Hydrokinetic power plants convert the energy of moving water into electricity.  They can operate on tidal currents, ocean waves, or on water flowing through rivers.  (To learn more, check out my summary of what's happening with hydrokinetics across the country.)

Waves breaking on the back shore of Great Cranberry Island, Maine.

In Maine, eight hydrokinetic tidal projects have won preliminary permits from the Federal Energy Regulatory Commission.  Preliminary permits represent the first step toward earning a license to build and operate a project.  Once a developer receives a preliminary permit for a site, that developer has the exclusive right for three years to file an application for a full license at that site.  Preliminary permits don't authorize project construction or operation, but rather reserve a developer's claim to a particular site to allow time for studying the engineering and business aspects of the project.

The eight Maine hydrokinetic projects with preliminary permits are:
  • Town of Wiscasset Tidal Resources, 10 MW on the Sheepscot River
  • Shearwater Design's Homeowner Tidal Power Elec Gen, 60 kW on the Kennebec River
  • The Power Company's Damariscotta Tidal project, 250 kW on the Damariscotta River
  • Tidewalker Associates' Half Moon Tidal Energy project, 9 MW on Passamaquoddy Bay
  • three projects by Ocean Renewable Power Company:
    • Cobscook Bay at 750 kW
    • Western Passage Ocgen at 1.2 MW
    • Kendall Head at 1.2 MW
  • Pennamaquan Tidal Power on the Pennamaquan River at 21.1 MW
In addition, the Bareneck Island project is currently seeking a federal license to actually develop and operate its project.