June 30, 2011 - court lets Monhegan offshore wind site move forward

A court has cleared the waters off the Maine island of Monhegan for the development of an offshore wind pilot project.  Back in December 2009, the Maine Ocean Energy Task Force selected Monhegan and two other sites -- Boon Island and Damariscove Island -- as test sites for offshore wind development.  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.

Connecting islanders to the mainland, the Sea Queen provides mailboat and passenger service to the Cranberry Isles.

Monhegan is a gem of an island.  Situated about 12 nautical miles offshore, the island supports a year-round population of about 75, with summers bringing about 6,000 visitors and summer residents ashore.  Monhegan is not connected to the mainland by electric transmission lines, with most of the electricity on the island coming from a 300 kW diesel generator.  To many,  the combination of community and ocean energy resources makes Monhegan an attractive test site for offshore wind.

The project is not without its opponents, though a court ruling last week has cleared at least one obstacle to project development.  In January 2010, shortly after the Monhegan site was selected, an environmental activist filed a lawsuit against the Maine Department of Conservation, arguing that the Department had illegally approved the Monhegan site without considering the impact of the project on birds, the environment, and the aesthetics of the project as viewed from the island.  The activist claimed to have legal standing to challenge the approval on grounds including a constitutional right to practice religion through conservation stewardship.  Last week, after reviewing the evidence upon which the Department made its decision -- 359 pages of documents assessing the impacts of the project -- Superior Court Justice Jeffrey Hjelm issued an order finding that although the activist did have standing to challenge the Department's action, the Department's decision complied with the law and is valid.

This ruling helps clear the way for the Monhegan project to move forward, but there are still more steps to be taken, including both engineering and regulatory hurdles to pass.  DeepCWind anticipates installing the first one-third scale test platform in 2012.

June 29, 2011 - hydrokinetic energy recap

In the past week, I've taken a look at how the Federal Energy Regulatory Commission regulates the development of hydrokinetic energy projects -- powerplants that produce electricity from the movement of water in forms like waves, tides, or undammed rivers.

A summer day at Preble Cove on Great Cranberry Island, Maine.

 Here's a quick recap of what we saw:

• Intro to hydrokinetics: a description of hydrokinetics, and examples of projects
• Permits and licenses: what kind of federal energy approvals do projects need?
• Issued preliminary permits for inland projects: mostly on the lower Mississippi River, but also Alaska, Arizona, and Michigan
• Issued preliminary permits for marine projects: mostly North Atlantic tidal, some Pacific wave-based
• Pending applications for preliminary permits: almost all for lower Mississippi, but also riverine in NY and NJ, and tidal in NJ and Massachusetts
• Issued licenses for hydrokinetic projects: one riverine project operating, one Pacific wave project surrendered
• Pending applications for licenses: one Pacific wave, one Maine tidal

 Up next: a closer look at what's going on with hydrokinetic energy in Maine.

June 28, 2011 - pending applications for hydrokinetic licenses

To wrap up our look at how hydrokinetic power projects are licensed, today I'll consider the currently pending applications for hydrokinetic project licenses.

Hydrokinetic power production entails the production of electricity from the energy of moving water: waves, tides, currents, or river flows.  Commercial projects, and even experimental pilot projects, generally need licenses from the Federal Energy Regulatory Commission.

Because hydrokinetic technologies are relatively new, FERC has issued only two licenses for hydrokinetic projects to date.  Two more license applications are pending, split between wave and tidal energy applications.

The pending hydrokinetic license application for wave energy is for the Reedsport OPT Wave Park in Oregon.  Developer Ocean Power Technologies (OPT) initially submitted its license application in January 2010.  If built, this would be the first commercial wave park on the west coast of the U.S.  The proposal is for an array of up to ten buoys, each of which could produce 150 kW.

The other pending hydrokinetic license application involves a tidal project in Maine.  Developer TideWorks has proposed a 5 kilowatt project in the Sasanoa River, near Bath.  This small project is proposed to provide power to a single-family dwelling on 15-acre Bareneck Island.  Because the project is proposed to have less than 5 MW of capacity, it may qualify for an exemption from licensing -- but must apply to FERC to obtain that exemption.

June 27, 2011 - licensed hydrokinetic energy projects

As we've looked at hydrokinetic power production -- generating electricity from the power contained in water moving as waves, tides, currents, or river flows -- we've seen how federal regulation fits into the development process.  Most hydrokinetic projects need approvals from the Federal Energy Regulatory Commission: a preliminary permit to study a site and reserve priority for filing a license application, a license itself, or an exemption from licensing.

To date, FERC has issued only two licenses for hydrokinetic projects, with two more license applications pending.  Of the two issued licenses, only one -- the Hastings, Minnesota project on the Mississippi River -- is in operation.  The Hastings project, P-4306, came online in 2009 as the country's first federally-licensed hydrokinetic project.  The license authorizes Hastings to install and operate two 100 kW turbines mounted on a barge, one of which is operational and produces about 35 kW of power on average.  The barge is anchored in the outflow of the Army Corps of Engineers’ existing 4.4 MW Lock & Dam 2, increasing the total hydropower produced at the site without modifying the dam.

The other project license was issued in 2007 for the 1.0 MW Makah Bay Offshore Wave Pilot Project in the Pacific Ocean about 2 miles offshore of Washington.  That 5-year license was intended to allow the developer to demonstrate the potential of wave energy conversion power plants to provide economic and environmental benefits to coastal communities.  Two years later, before the project had broken ground, licensee Finavera Renewables Ocean Energy, Ltd. filed an application to surrender its license.  In the surrender application, Finavera noted that the project had become uneconomic given the economic climate and limited capital.  FERC accepted the license surrender in 2009.

June 24, 2011 - what's in the near future for hydrokinetic energy

Hydrokinetic projects produce electricity from moving water like tides, waves, ocean currents, or rivers.  This week I've looked at some of the 70 preliminary permits for hydrokinetic projects issued by the Federal Energy Regulatory Commission; today, I'll expand that look to cover the 147 more preliminary permit applications pending before FERC. Interestingly, these pending applications focus nearly exclusively on inland riverine projects, which may give some insight into the near-term future of hydrokinetic energy projects in the U.S.


Looking at the projects for which permits have already been issued, half are for inland projects on rivers, mostly on the lower Mississippi River system below Cairo, Illinois.   The list of pending projects is skewed even more heavily toward inland sites, with 145 out of 147 pending applications being for inland projects, and accounting for well over 99.9% of the total 17,352.55 MW of capacity proposed in these applications.

140 of the pending hydrokinetic preliminary permits are clustered densely along the lower Mississippi system.  These sites claim a total potential capacity of over 17 GW -- a significant amount of power.  Two companies have filed for the bulk of these preliminary permits: Free Flow Power, which has 24 active permits for sites on the Mississippi and which has filed for 105 more permits; and Northland Power Mississippi River, which has applied for preliminary permits at 40 Mississippi River sites.  These two players will have to battle before FERC to resolve their 28 permit applications seeking competing claims to the same site.

Rounding out the pending applications for preliminary permits for inland projects are two on the Niagara River in New York between Lakes Erie and Ontario, and one on the Cohansey River in New Jersey.

The remaining 2 pending permits are for tidal projects in the northeast quadrant of the country: the 3 MW Maurice River Tidal Energy Project in New Jersey, and the 8 MW Muskeget Channel Tidal project between the town of Edgartown on Martha's Vineyard and Nantucket.

FERC's preliminary permit process for hydrokinetic projects applies to a variety of technologies, including marine waves, currents, and tides, as well as flowing water in rivers.  The distribution of interest in preliminary permits suggests that large river systems like the Mississippi hold great potential for the commercial development of hydrokinetic energy.  Will inland hydrokinetic technology -- arguably the direct descendant of traditional hydroelectricity -- continue to draw more interest than marine hydrokinetic power?

June 23, 2011 - where are the coastal hydrokinetic projects?

Continuing my look at hydrokinetic energy conversion, let's look at where FERC has issued preliminary permits for coastal hydrokinetic projects.

What this local waterfall in the coastal Maine woods lacks in usable power is made up for by its charm.

A hydrokinetic project generates electricity from moving water without a dam: tides, waves, ocean currents, or unimpounded rivers.  FERC has issued 70 preliminary permits for hydrokinetic projects, half of which are for inland projects on rivers, mostly on the lower Mississippi.  The other half of preliminary permits are for coastal projects.  Of these, 27 permits are for tidal projects, with another 8 permits for wave-powered projects.

The ocean's waves can provide significant amounts of power, particularly in certain areas of the coastline.  The Pacific coasts of Alaska, Washington, Oregon, and California are home to seven of the 8 preliminary permits for wave projects, with Hawaii hosting the eighth.

Tidal power is behind the remaining preliminary permits for hydrokinetic projects.  These projects are clustered along the northern half of both U.S. coasts.  Maine is home to 8 preliminary permits, with 4 more in New York, 4 in New Jersey, and one each in New Hampshire and Massachusetts.  Alaska sports 6 projects, with 2 in Washington and 1 in California.

June 22, 2011 - where are the inland hydrokinetic projects?

This week I’ve been looking at what it takes to test or develop a hydrokinetic power plant: technology that can generate electricity from moving water without a dam.  Today, let's look at the geographic pattern revealed by mapping out proposed projects.

Sand dunes on Hermit Island, Phippsburg, Maine.

A hydrokinetic project generates electricity from moving water without a dam: tides, waves, ocean currents, or unimpounded rivers.  Based on this definition, the hydrokinetic opportunity exists primarily 

near coasts or on major inland rivers.   

As of June 2011, FERC has issued 70 preliminary permits for hydrokinetic projects, totaling 9,306 MW.  Half of these preliminary permits are for inland projects on rivers, mostly on the lower Mississippi system below Cairo, Illinois.  Riverine hydrokinetic projects offer some of the benefits of conventional dam-based hydropower -- like generating renewable electricity from flowing water -- but do not involve the construction of a dam.  This can reduce both project costs and environmental impacts.  In a culture where more dams are being removed from our rivers than are being built, siting a riverine hydrokinetic project may be easier than permitting a new dam.

Beyond the lower Mississippi system, FERC has issued preliminary permits for inland hydrokinetic projects on the Tanana, Kvichak and Yukon Rivers in Alaska, the Colorado River in Arizona, and the St. Clair River in Michigan.

June 21, 2011 - more on hydrokinetic energy

Yesterday, I started a look at the potential of generating electricity from moving water: hydrokinetic energy.

The Doughty Dam in North Berwick, Maine.  The hydropower at this site was responsible for the settling of North Berwick.

Let's say you have a new technology to generate electricity from moving water, and you've found a site where you'd like to try it out.  While you have a limited opportunity to test turbines without getting a license from the Federal Energy Regulatory Commission, most hydrokinetic projects will need to get FERC approvals such as a preliminary permit, license, or exemption from licensing.

A preliminary permit is the traditional first step toward getting a FERC license.  Once you get a preliminary permit, you have first priority to file an application for a full license at that site within three years.  While the permit doesn’t authorize you to build or run the project, it secures your exclusive right to acquire a license for your site during the permit’s term.

The next step is securing a license.  FERC encourages projects, even small or experimental ones, to secure licenses.  In fact, after Verdant Power tested its turbines near New York City for several years, FERC has recommended licensing Verdant Power’s 1 MW Roosevelt Island Tidal Energy (RITE) Project as a pilot project.

Compared to traditional licensing, pilot project status qualifies an applicant for an expedited review process.  Pilot projects must be small; FERC applies a case-by-case determination of whether a project qualifies for a pilot license, so there is no bright line for how big is too big.  Guidance suggests 5 MW is a reasonable size cap, with some projects expected to be “substantially smaller”.

Pilot project licenses are short term – generally 5 years.  Pilot projects are also intended not to be permanent on their own; unless the developer gets a new license before the pilot license expires, the developer must remove the project and restore the site when the pilot license expires.  On the other hand, a pilot project license is one step closer to ultimate licensure, as compared to unlicensed testing.

Hydrokinetic technology holds great promise, and developers are lining up to capitalize on it.  As of June 2011, FERC has issued 70 preliminary permits for hydrokinetic projects, totaling 9,306 MW.  147 more preliminary permit applications are pending – interestingly, 145 of which are on inland waterways.  79 hydrokinetic projects with 8,002 MW capacity have entered the pre-filing process for licensure, with 3 more projects in the post-filing phase.

June 20, 2011 - hydrokinetic power

Flowing water contains large amounts of usable energy.  Beyond traditional dam-based hydroelectric generation, water’s power can be captured using hydrokinetic technology.  A hydrokinetic project generates electricity from moving water: the flow of tides, waves, ocean currents, or unimpounded rivers.  Most hydrokinetic projects will need regulatory approval from the Federal Energy Regulatory Commission, a process that is still evolving but is getting easier over time.

The Oyster River Dam in Durham, NH.

While humans have long recognized the power of moving water, cost-effective technologies for converting this power into electricity are still in their infancy.  The U.S.’s first federally-licensed hydrokinetic project was commissioned in 2009.  This project on the Mississippi River in Hastings, Minnesota features a 100 kW turbine mounted on a barge tethered in the output channel of an existing hydropower plant: the Army Corps of Engineers’ 4.4 MW Lock & Dam 2.  Under typical operating conditions, the Hastings project produces 35 kilowatts of power.

Technology continues to evolve rapidly, and each new design has to be tested.  Under limited circumstances, developers can test turbines without obtaining a FERC license.  In 2005, dealing with Verdant Power’s testing of underwater turbines in the East River in New York City, FERC ruled that a license is not required for a hydrokinetic project if the technology is experimental; the proposed facilities will be used for a short period for studies needed to seek a license; and the power generated from the test project will not be transmitted into, or displace power from, the electric grid.

This opportunity to test turbines without a license is limited.  Most hydrokinetic projects will need to get FERC approvals such as a preliminary permit, license, or exemption from licensing.  Tomorrow, I'll look at some of those paths toward developing and operating a renewable hydrokinetic energy project.

June 16, 2011 - will EPA rules increase electric rates?

The EPA is charged with balancing environmental protections against their costs -- and is now drawing fire for how it balanced costs versus benefits in its tighter regulation of emissions from fossil-fired electric generation.

Earlier this year, the U.S. Environmental Protection Agency proposed a new set of rules limiting emissions from power plants.  These regulations, called the Mercury and Air Toxics Standards, create new standards for emissions from coal- and oil-fired electricity generation.  Under the new EPA standards, these plants must meet emission requirements; some plants need expensive retrofitting to comply, while others may not be able to upgrade their emissions controls in a cost-effective manner.  For example, American Electric Power (AEP), responded to the proposed rule by accelerating its plans to retire 5 large coal-burning power plants, and to retrofit other plans to meet emissions thresholds or switch to natural gas as a fuel.

As for the benefit side of the equation, in a factsheet about the standards, EPA estimates the health benefits associated with these emissions reductions are $59 billion to $140 billion in 2016 (in 2007 $), with total national annual costs of $10.9 billion in 2016.

This calculation of costs is challenged by pro-coal interests.  The American Coalition for Clean Coal Electricity commissioned a study suggesting that EPA's new rules will make electricity costs increase by $184 billion, or $17.8 billion per year.  If this happens, the coal lobby's study suggests that average U.S retail electricity prices in 2016 will increase by about 12 percent, with some regions facing 24 percent price hikes.  For example, the Chicago Tribune projects consumer rate impacts of an increase of from 40 to 60% over current electric bills.  AEP reportedly thinks that retooling its operations to comply with the new EPA rules will require $6 billion and $8 billion in capital investments over the next ten years, resulting in the loss of 600 jobs and an increase in electricity prices of 10 to 35%.

EPA is considering public comments on these proposed rules through July 5, but that period may be extended.  Last week, a coalition of House Democrats sent a letter to EPA Administrator Lisa Jackson asking for a 60-day extension of the public comment period.

June 15, 2011 - Nova Scotia feed-in tariff

Nova Scotia is poised to set favorable rates for community-scale renewable electricity projects.  This community-based feed-in tariff can help small projects get off the ground.

Back in April 2010, the Nova Scotia provincial government released its Renewable Electricity Plan (32-page PDF).  This document, subtitled “A path to good jobs, stable prices, and a cleaner environment”, sets forth a detailed plan “to move Nova Scotia away from carbon-based electricity towards greener, more local sources, and sets a commitment to reach 25% renewable electricity supply by 2015 – and a nonbinding goal of 40% by 2025.

While the plan envisions that most of the new renewable energy needed to meet these goals will come from “industrial-scale projects”, a key element of that plan targeted at smaller projects is the community-based feed-in tariff (COMFIT).  The COMFIT is designed to benefit 100 megawatts of qualified renewable projects connected to the grid at the distribution level.  To qualify for the COMFIT, a project must be developed or owned by municipalities, First Nations, co-ops, or non-profit groups, or be a small business operating through Community Economic Development Investment Funds.

Feed-in tariffs are widely used in the global renewable energy context.  As the Nova Scotia plan notes, “[m]ore than 45 jurisdictions around the world, including Spain, Germany, Ontario, and Vermont, have established feed-in tariffs (FITs) that support and encourage small-scale and community ownership.”

In Nova Scotia’s case, the feed-in tariff plan is designed to start small, with a limit of 100 MW of pilot projects.  The plan explains this cautious approach by noting that it is technically difficult to interconnect intermittent generation at the distribution level.  The plan also describes the balancing act between facilitating small-scale development while keeping ratepayer costs low:

Government has chosen not to extend the COMFIT to larger projects. Just as a commercial farm can produce vegetables cheaper than a garden patch, an industrial-scale wind farm can produce electricity cheaper than a backyard turbine. There are many economies of scale in renewable power production. Nevertheless, a conscious decision has been made to encourage small as well as larger renewable electricity projects. This is partly to ensure widely dispersed energy sources, and partly to encourage rural community economic development. A FIT will result in somewhat more expensive electricity than open competitive bidding, but it gives these smaller projects a degree of market certainty.

The plan continues:

Renewable electricity produced from small local projects will be slightly higher priced than electricity from large-scale projects. But since the total amount of power from COMFIT projects will start out small, the overall impact on rates is low—estimated at less than one percent on a typical consumer’s bill. Of course until the UARB sets the COMFIT rate, and we see how fully it is taken up, the precise impact can’t be calculated with certainty.

The Nova Scotia Utility and Review Board has held a public hearing on the COMFIT program rates, and is expected to issue an order finalizing tariffed rates early this summer.  Staff's consultant proposed the following tariff rates:

• $452 per MWh for wind projects ≤50 kW
• $139 per MWh for wind projects >50 kW
• $156 per MWh in year 2012 for biomass CHP projects, composed of a fixed component of $94 per MWh and an escalating component of $62 per MWh representing the cost of fuel
• $140 per MWh for run-of-river hydro projects
• $652 per MWh for in-stream tidal projects.

June 14, 2011 - tortoise threat to California solar project lifted

Concerns about environmental impacts play a big role in energy policy decisions.  Concerns over the impacts of running traditional fossil-fueled generation helped create a market for renewable power.  At the same time, concerns about the local impacts to wildlife of siting a particular renewable project can make the project cost-prohibitive or even impossible.

BrightSource Energy has been building a large solar power project in California's Mojave Desert.  Construction of Phase I of the 392 MW Ivanpah solar project broke ground in October 2010, with two subsequent phases slated for development shortly thereafter.  As construction progressed, the developer ran into tortoises at the site -- more tortoises than were assumed when the project got a key approval from the federal Fish and Wildlife Service.  In April 2011, BrightSource was advised by the U.S. Bureau of Land Management that BrightSource needed a revised biological opinion from the Fish and Wildlife Service that the project development wouldn't harm the threatened desert tortoise.  BrightSource stopped construction of units 2 and 3 of the project.

Now, BrightSource is back to work.  Last week, the Fish and Wildlife Service issued a biological opinion that the project will not endanger tortoises, provided that a list of stipulations are followed: ranging from relocating tortoises and predator protections, to fencing and an employee environmental awareness program.
 

This story illustrates an example of how concerns over environmental quality shape energy policy.  For project developers and wildlife defenders alike, it also suggests that we have ways to balance competing environmental concerns such as tortoises and clean renewable energy.

June 13, 2011 - RGGI carbon auction results

The latest carbon auction results from the RGGI program show a market in uncertainty.

The "Old Woolen Mill" on the Great Works River in North Berwick, Maine.

The Regional Greenhouse Gas Initiative (RGGI) is the first market-based greenhouse gas regulatory program in the United States.  RGGI represents a cooperative effort by Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont.  These ten states agreed to cap and reduce their electrical energy sector's greenhouse gas emissions by 10% by 2018.

While each state's legislature implemented its own version of the compact, the overall structure is that carbon allowances are auctioned off to the power sector.  Proceeds from these auctions are invested in energy efficiency, renewable energy, and other clean energy technologies.  The program has been a success in creating jobs, reducing greenhouse gas emissions from the power sector, and funding high-yield energy efficiency projects at businesses.

RGGI just held its twelfth auction.  (You can read the market monitor's report, a 10-page PDF, here.)  Altogether, the auction raised $25.5 million.  Each participating state's energy programs get a share in those proceeds based on how the underlying carbon allowances were allocated; for Maine, the twelfth auction yielded just under $770,000.  Since 2007, Maine has received $26 million through the program, which has been invested in energy efficiency through the Efficiency Maine Trust.

Interestingly, only 30 percent of the current-period carbon allowances available in the auction actually changed hands.  This low demand for allowances is striking, particularly since the price was as low as it could be: the auction floor price of $1.89 per short ton of CO2.  This apparent oversupply has emerged as the RGGI market matured; in the initial auction, the bid demand was four times larger than the supply.  While supply first outpaced demand for the tenth auction, held in December 2010, the 30% figure represents a new low for auction demand.

RGGI's thirteenth auction is scheduled for September 7, 2011.

June 10, 2011 - Idaho restricts wind/solar incentive

Regulators in Idaho have restricted an incentive for certain small wind and solar projects, but renewable projects can still qualify for the right to sell their power to utilities.  At its heart, the issue is an old one: who should pay for renewable development, and how much should they pay.

The federal Public Utilities Regulatory Policy Act of 1978 (PURPA) authorizes FERC to require utilities to purchase power from renewable “qualifying facilities”.  Under PURPA, utilities must sign contracts  with qualifying facilities to buy their output at a rate capped at the utility's "avoided cost", or marginal cost to produce the next incremental kilowatt-hour.

Because utilities’ avoided costs are typically set based on the default fleet of generators, a qualifying facility cannot use PURPA to receive a price premium over the marginal conventional resource.  However, having the right to require a utility to buy your power is a valuable incentive for developing a renewable project. 

Each state sets the avoided cost rates for its own qualifying facilities.  In Idaho, large generators have to negotiate individual avoided cost rates with utilities.  To help smaller qualifying facilities, projects smaller than a specified threshold don’t have to negotiate, but can sell power to utilities at “published” avoided cost rates which are generally more favorable for project developers.

Where that threshold is set affects who can qualify for those published rates.  Originally, facilities whose average output was 10 MW or smaller qualified for the published rates.   However, utilities complained to the Idaho Public Utilities Commission, asking for the threshold to be lowered to 100 kW.  Utilities complained that ratepayers should not have to bear above-market costs, particularly not costs in excess of the actual avoided cost limit set by PURPA.  Commenters also complained about large projects trying to circumvent the threshold by characterizing themselves as a series of smaller projects in order to qualify for the incentive.  At the end of 2010, the Commission temporarily reduced the threshold to 100 kW for wind and solar resources, leaving it at 10 aMW for other resources. 

This week, the Idaho Public Utilities Commission has issued an order (Order No. 23362, 10 page PDF) leaving the lowered 100 kW threshold for wind and solar in place.  The Commission noted that it would be "illegal pursuant to PURPA" to allow large projects to obtain a rate that does not accurately reflect the utility's avoided cost.  As a result, Idaho wind and solar projects' right to sell power at the more favorable published avoided cost rates is now limited to projects smaller than 100 kW.  Larger projects can still avail themselves of negotiated avoided cost rates.

June 9, 2011 - Connecticut restructures its regulation of energy

In an attempt to lower electricity rates and promote clean energy, Connecticut's state legislature has passed legislation reforming key regulatory agency structure.  Governor Dannel Malloy is expected to sign the bill later this month.

Connecticut has high electricity prices.  According to the Energy Information Administration, Connecticut had the second-highest prices in the nation in 2009 -- an average retail price of 18.06 cents per kilowatt-hour.  Only Hawaii has more expensive electricity.  (EIA's most recent monthly data, for February 2011, keeps Connecticut in second place.)

To address this concern, the bill, S.B. 1243, shuffles energy regulatory responsibilities into a new agency, the Department of Energy and Environmental Protection.  (DEEP -- quite a catchy acronym.)  DEEP would be formed by merging the existing state Department of Environmental Protection with the Department of Public Utility Control, and the energy staff from the Office of Policy and Management. Proponents argued that giving one agency comprehensive responsibility for energy policy would ensure consistent regulation.  Connecticut has not had such a one-stop shop for energy policy in over 30 years.

As an example of how DEEP can provide one-stop shopping, S.B. 1243 also creates an Office of Energy Efficient Business within DEEP.  This office is designed to help businesses connect with opportunities, technology and funding for energy efficiency and renewable energy projects.

The bill also creates the Clean Energy Finance and Investment Authority (CEIFA).  CEIFA's stated purpose is to facilitate private capital investment in clean energy projects by pursuing maximal leveraging of public dollars.  In this role, CEIFA succeeds the Renewable Energy Investment Board, the statutorily-created entity that has been managing the Connecticut Clean Energy Fund.  

In recognition of the role that long-term contracts can play in hedging volatility and reducing electricity costs, S.B. 1243 would require DEEP to develop an annual plan for competitive solicitations and procurement of energy and wholesale electricity market products "that will enable each electric distribution company to manage a portfolio of contracts to reduce the average cost of standard service while maintaining standard service cost volatility within reasonable levels."

Will the agency shuffling lead to a tangible improvement in Connecticut's development and implementation of energy policy?  Will Connecticut's embracing of state-sponsored energy procurement reduce ratepayer costs?  With strong legislative support and the Governor's signature expected shortly, time will tell whether S.B. 1243 represents a step forward for Connecticut's energy policy.

June 8 - BP reports China passes US in energy consumption

As China's economy grows, it appears to have passed the U.S. in terms of total energy consumption.

Back in July 2010, I noted that the International Energy Agency claimed that China had passed the U.S. in terms of total energy consumed.  That IEA report showed that China used 2.252 billion tons of oil equivalent, whereas the U.S. used only 2.170 billion tons of oil equivalent.

Now, another observer (and key energy player) has confirmed China's leap to being the top energy consumer.  BP’s 60th annual Statistical Review of World Energy corroborates the IEA's findings, placing China in the top consumer slot as of 2010.  According to BP, China consumed 20.3% of total global energy demand last year.  This beats the U.S., which BP reports consumed 19% of the total global energy demand for 2010.

This reverses the trend for more than the past 100 years, when the United States has been considered to consume more energy than any other country. While energy consumption has traditionally been viewed as directly correlated to GDP, this shift breaks that trend as well. Commentators point to China's increased industrial activity, particularly significant in light of the current state of the American economy.

Interestingly, American energy intensity remains high: the average U.S. citizen uses five times as much energy as does the average Chinese citizen. What will happen when China reaches the energy intensity of the U.S.?

June 7, 2011 - Washington dam removal in process

While state and federal governments pursue policies supporting the development of new renewable energy resources, existing hydroelectric dams are being removed.  Last year, I noted the plan to remove the Elwha and Glines Canyon Dams on the Elwha River on Washington's Olympic Peninsula.  That plan is moving forward; last week, after 99 years of producing renewable power, the dams' electricity-generating turbines have now been turned off.

The Elwha River restoration project will be the largest dam removal in U.S. history.  All told, the dam removal project is projected to cost $324.7 million.

The Elwha project is made more interesting by its factual context, including land conservation, fish impacts, and sedimentation.  Much of the river's 45-mile course runs through Olympic National Park, making power generation a use some feel is incongruous with the watershed's protected status.

The Elwha River was formerly home to impressive runs of anadromous fish, including salmon, which have been an important part of local native Americans' culture.  In 1910, the river produced approximately 390,000 wild salmon and sea-run trout, but that number dropped more than 99% to only about 3,000 wild native salmonids in 2005.  The dams are believed to have played a part in this decimation of that fish stock.

Thanks to the glacier-fed nature of the watershed, massive amounts of sediment have built up behind the dams -- perhaps as much as 24 million cubic yards, or enough sediment to cover almost 15,000 acres one foot deep.

Dam demolition and removal itself is scheduled to begin September 17, 2011. 

June 6, 2011 - concentrating solar

Today, a quick look at concentrating solar power technology and its potential to power business and society.

When most people think about solar power, they picture solar photovoltaic panels: rectangular panels composed of a grid of individual solar PV cells, mounted perhaps on a building's roof or a nearby stand.  Photovoltaic cells convert solar energy into electricity, which flows through wires to power electric equipment.

Some people might also think of solar hot water panels, which function somewhat like a greenhouse and use solar energy to heat water circulating through a series of pipes or hoses.  The hot water can then be used for domestic hot water (perhaps after a secondary heating in a more traditional water heater) or for space heating.

Spread around houses or commercial buildings, these two solar energy conversion technologies - solar photovoltaics and solar thermal - have significant potential as distributed energy resources.

At the utility scale, it can be more cost-effective to concentrate the Sun's rays before converting the energy into a usable form, particularly if electricity is the desired end product.  In a concentrating solar application, a series of mirrors -- an array of either flat panels or trough-shaped parabolic mirrors -- can be used to concentrate the solar energy from a large surface area of the ground onto a relatively small area.  Concentrating solar technology works for both photovoltaics and for thermal systems.  In fact, given the larger amount of solar energy that is brought to bear through concentration, solar energy can be used to evaporate water into steam directly.  Concentrated solar energy can also be used to heat another medium, like molten sodium, which can in turn be used to evaporate water into steam.  The resulting steam can be used to spin turbine and generator sets to produce electricity.

Not all sites are well suited for concentrating solar, and today's technology continues to be refined through research and development.  The coming years may show whether photovoltaics or thermal installations prove more cost-effective.  For now, the race is on.