Fishermen's Energy gets offshore wind approval

Thursday, July 26, 2012

A New Jersey offshore wind developer has obtained its final permit or regulatory approval needed to begin construction of its project off Atlantic City.  Fishermen’s Energy received a Clean Water Act individual permit from the U.S. Army Corps of Engineers.  This approval could clear the way for actual construction of the project in the next two years.

A bumper sticker for Fox Islands Wind recently seen in the parking lot for the ferry from Rockland, Maine, to the island of Vinalhaven.  Fox Islands Wind has installed three turbines on the island, making it an onshore wind project on an offshore island.  Are offshore turbines next?

Fishermen's Energy envisions two phases of development off New Jersey.  The Fishermen’s Atlantic City Windfarm or FACW would be in state waters within 3 miles of the coast of Atlantic City.  The FACW project is expected to cost about $200 million, and will include five or six turbines in a linear array for a total nameplate capacity of 25 MW.  A submarine cable will connect the FACW to the mainland transmission grid operated by PJM, with power from the FACW being sold to New Jersey electric customers.  A second larger phase could occur in federal waters.

With the Army Corps permit in hand, Fishermen's Energy plans to start building the FACW onshore in Atlantic City in 2013, moving construction offshore and commissioning the project in 2014.

Fishermen's Energy is still waiting for the New Jersey Board of Public Utilities to decide whether to require mainland utilities to purchase the project’s output.  Fishermen's Energy has asked the Board to approve its FACW project for the state's OREC program, which allows qualified offshore wind generators to produce ORECs and then creates a market for them by requiring utilities to procure ORECs.  That case remains pending.

NJ tweaks solar energy law

Wednesday, July 25, 2012

New Jersey Governor Chris Christie has signed into law a bill designed to support the Garden State's solar energy industry.  The bill, which amends New Jersey's electric renewable portfolio standard, is hoped to remedy a perceived oversupply in the state market for solar renewable energy certificates, or SRECs.

Under New Jersey law, electric public utilities are required to source a specified portion of their power from solar electric generating facilities.  This solar-produced power is represented by SRECs, a tradable commodity issued by the New Jersey Board of Public Utilities to generators for each megawatt hour of solar energy they generate from grid-connected facilities.

Solar photovoltaic panels on the roof of Gallagher's Auto Parts, in Patten, Maine.

New Jersey's renewable portfolio standard requires utilities need to procure a specified amount of SRECs.  When the law first took effect, New Jersey had a shortage of eligible installed solar generation compared to this legislative demand, so SREC prices were high -- over $600 per MWh.  These prices were a significant incentive to develop solar capacity.  New Jersey installed more solar capacity in the first quarter of 2012 than any other state, and led the nation in solar installations on commercial and industrial properties in 2011. Today there are over 16,000 solar installations throughout the state, totaling over 800 MW in installed solar capacity.  Another 600 MW of solar capacity is in various stages of installation.

As New Jersey experienced significant growth in solar capacity, SREC supplies grew to the point where they exceeded the level of utility demand required by the renewable portfolio standard.  SREC prices fell below $200 on spot markets.  These low prices hurt solar developers and other stakeholders whose financing is reliant on REC sales and assumed higher prices.

The bill signed into law this week, "An Act concerning certain electric customer metering and solar renewable portfolio standards requirements and amending P.L.1999, c.23" (available as Senate Bill 1925 and Assembly Bill 2966), is designed to fix this problem.  It increases the amount of solar energy utilities must buy in the near-term.  As of June 1, 2013, the state’s solar energy mix will change from a fixed megawatt-hour requirement to a percentage-based requirement.  In proximate years, the change will represent an increase over the current solar carve-out; over time, it will return to the currently-planned arc of solar requirements.

The exact effect of the new law on SREC markets remains to be seen.  With a short-term increase in SREC demand, prices may rise, leading more projects to come online.  Will the short-term accelerated increase in demand lead to long-term price support, more development, both - or neither?

Electric vehicle pilot program proposed in Maine

Monday, July 23, 2012

A pilot program proposed by a Maine utility could lead to more electric vehicles on the road.  Central Maine Power Co. has asked the Maine Public Utilities Commission to approve its Electric Vehicle Pilot Project No. 2, which includes a limited number of grants to help customers purchase or lease an electric vehicle. 

As described in CMP's June 21 filing with the Commission, the electric vehicle pilot project consists of grant funding, CMP promotion of electric vehicles, and the collection of data on vehicle usage.  CMP envisions issuing cash grants of up to $15,000 each to ten selected organizations located in CMP’s service territory.  These organizations, selected through a public solicitation process, could use these grants to help them purchase or lease ten electric vehicles.  Each organization can also apply a portion of the grant toward the purchase and installation of a Level 2 (208V or 240V) rapid charging station, if it so chooses.

The project arises out of a requirement approved by the Commission as part of the settlement of a 2008 case over CMP's Maine Power Reliability Program, or MPRP.  As part of a deal allowing CMP to invest $1.4 billion in transmission infrastructure in its territory, the Commission required CMP to develop a process for pilot projects to facilitate the increased use of hybrid and electric cars in Maine, and to promote the storage of renewable and other energy generated off-peak to replace fuels with greater climate impacts.  Using off-peak electricity to power transportation could both save money for consumers and allow the utility to make more full use of its transmission and distribution grid.

Specifically, the stipulation required CMP to bring forward at least three pilot projects to facilitate the increased use of hybrid and electric cars by the end of 2012.  CMP's first pilot project entails integrating a limited number of electric vehicles into CMP's fleet.  This project, which is currently being implemented, is designed to give the utility first-hand experience with EVs, in a manner that minimizes costs and risks.

If approved, CMP's second project would introduce ten vehicles into the broader community.  The utility has said that its objective is to build awareness and lessen consumers' concerns by getting more of the new EV models into the public's hands.  Its ultimate stated goal is to create interest and "buzz" about EVs, particularly among innovative early adopters who would be most likely to purchase an EV.

A third phase is still under development, but CMP has said it will propose reducing barriers to EV use through education, participate in the development of public charging infrastructure, and assess a lower off-peak rate for EV charging.

The Maine Public Utilities Commission is reviewing CMP's proposal and is expected to issue its decision later this year.

FERC, BOEM marine hydrokinetic guidelines

Friday, July 20, 2012

Two key federal regulators of marine renewable energy production have issued an updated set of guidelines for regulatory aspects of marine and hydrokinetic energy projects.

The document, BOEM / FERC Guidelines on Regulation of Marine and Hydrokinetic Energy Projects on the OCS, is designed to to clarify jurisdictional responsibilities for marine and hydrokinetic projects on the Outer Continental Shelf (OCS) and to foster a cohesive, streamlined process that will help accelerate the development of MHK (i.e., wave, tidal, and ocean current) energy projects.

U.S. Coast Guard icebreaking tug THUNDER BAY at its home berth in Rockland, Maine.

The OCS includes all submerged lands, subsoil, and seabed lying between the seaward extent of the states' jurisdiction (approximately 3 nautical miles from shore, or 3 marine leagues for Texas and the Gulf coast of Florida) and the seaward extent of federal jurisdiction (approximately 200 nautical miles or more from shore).

As described in the guidelines, an MHK project generates electricity from the motion of waves or the unimpounded flow of tides, ocean currents, or inland waterways. (While ocean thermal energy conversion or OTEC projects also fall under the MHK umbrella, the new guidelines focus on ocean wave and ocean current technologies.)

The guidelines cover only MHK projects on the OCS. The guidelines therefore cover neither nearshore MHK projects in state-jurisdictional waters, nor offshore wind projects in federal or state waters
The guidelines published yesterday fit within the larger context of agreements between previously-sparring federal agencies.  BOEM regulates site leasing, while FERC regulates hydropower.  As marine hydrokinetic technologies improved to the point where developers began proposing commercial projects, tensions and inconsistency developed between how the two agencies regulated and interacted.

This situation led the U.S. Department of the Interior and FERC to execute a Memorandum of Understanding (MOU) in April 2009, recognizing each agency’s respective jurisdiction.  Under the agreement, BOEM has jurisdiction to issue leases on the OCS for MHK projects, while FERC has jurisdiction to issue licenses for these same projects. The agencies felt that the agreement established a cohesive, streamlined process to lease, license and regulate all renewable energy development activities on the OCS, including marine hydrokinetic sources.

FERC and BOEMs’ predecessor Minerals Management Service (MMS) issued the first set of joint guidelines in 2009. As part of MMS’s Guidelines for the Minerals Management Service Renewable Energy Framework, the agencies included an appendix presenting MMS / FERC Guidance on Regulation of Hydrokinetic Energy Projects on the OCS. That document covered procedures for obtaining leases and licenses, municipal preferences, fee structures, and procedures for pursuing hybrid projects (more than one form of renewable energy) or straddle projects (straddling the boundary dividing state waters and the OCS).

Yesterday’s announcement presents a refreshed version of these guidelines. The revised guidelines offer guidance on a number of key regulatory aspects of MHK development process. Since 2009, both FERC and BOEM have changed some of their processes in significant ways – for example, BOEM now allows research leases, and FERC has expedited its pilot project licensure process. The guidelines thus help developers and others in the marine community to understand the legal process for exploration and development of hydrokinetic ocean energy sites.

Does blending ethanol in transportation fuels lower costs?

Thursday, July 19, 2012

While widespread drought has driven corn prices up in the U.S., pinching ethanol producers, debate has emerged about the economic impacts of blending corn-based ethanol into gasoline and diesel used as transportation fuel.

As local gas pumps may tell you, U.S. transportation fuels may contain ethanol.

Under the EPA's U.S. Renewable Fuel Standard program, transportation fuel sold in the United States must contain a certain amount of renewable fuel.  Corn is the feedstock for the vast bulk of the ethanol biofuel used to meet the renewable fuel standard.  Despite near-record levels of corn planting, drought across much of the country has led to crop reductions and high prices for corn.  At the same time, the demand for gasoline and diesel has not grown as it had been projected to do.  This slackening of demand comes from both increases in vehicle energy efficiency and decreases in fuel demand due to the economic slowdown.  Between higher feedstock costs and reduced product demand, many biofuel ethanol producers are struggling or failing to turn a profit.

Some policy questions surrounding the blending of corn ethanol into transportation fuel remain controversial.  One argument used to support the practice points to evidence that blending ethanol into gasoline and diesel reduces the cost of fuel.  A widely-cited study by Xiaodong Du and Dermot Hayes titled "The Impact of Ethanol Production on U.S. and Regional Gasoline Markets" found that over the period of January 2000 to December 2011, growth in ethanol production for fuel reduced wholesale gasoline prices by an average of $0.29 per gallon.  Looking at 2009 alone, they reported that the average effect across all regions increased to $1.09/gallon, with regional price suppression  impacts ranging from $0.73/gallon in the Gulf Coast to $1.69/gallon in the Midwest. 

Not so, according to a study released earlier this month by Christopher Knittel and Aaron Smith.  Their July 12, 2012 paper, Ethanol Production and Gasoline Prices: A Spurious Correlation, disputes many of the findings of Du and Hayes's research.  In Knittel and Smith's view, the previous researchers' results were "driven by implausible economic assumptions and spurious statistical correlations".  Like Du and Hayes, Knittel and Smith provide a detailed analysis of the "crack spread" and "crack ratio", measures of the margin associated with refining.  They challenge the accuracy of the previous study's results, arguing that "the empirical results are extremely sensitive to the empirical specification; however, empirical models that are most consistent with economic theory suggest effects that are near zero and statistically insignificant."

Which view is more accurate is a question that remains to be seen.  The answer may have implications for the future course of U.S. policy on blending corn-based ethanol into gasoline and diesel fuels used for transportation.

Maine court sustains challenge to smart meter project, partially

Wednesday, July 18, 2012

The Maine Supreme Judicial Court has issued an opinion that calls into question the Maine Public Utilities Commission's dismissal of a complaint against a utility regarding its use of smart-meter technology.  With over 600,000 smart meters already installed, what the court ruling means is unclear.

In 2010, the Commission approved a proposal by Central Maine Power Company (CMP) to install smart meters on its customers' sites.  The project, which CMP called Advanced Metering Infrastructure, entailed replacing existing customer meters with "smart meters" capable of transmitting customer usage data back to the utility using radio frequency signals.

The project triggered a series of customer complaints raising concerns about the health and safety of smart-meter technology associated with the AMI project, focusing on the health effects of RF radiation emitted by the wireless smart meters and the technology’s potential to violate individuals’ privacy.  Customers also complained about the lack of an opt-out provision allowing customers to choose to retain their existing meters.

In 2011, the Commission ordered CMP to provide two alternatives for customers who choose not to have the standard wireless smart meter installed on their premises: either a standard meter, or a smart meter set to receive-only mode.  Under the Commission's order, customers opting out would pay an extra fee.

In response, nineteen CMP customers filed a complaint against both CMP and the Commission, challenging the opt-out fee.  The Commission dismissed that complaint, finding that it had considered and resolved the issues raised in the complaint by ordering CMP to allow customers to opt out.  This dismissal triggered an appeal by the customers to the Maine Supreme Judicial Court.

In the court's opinion issued last week, Friedman v. Public Utilities Commission, the court agreed with the customer complainants that the Commission should not have dismissed the portion of the complaint against CMP addressing health and safety issues.

In reaching this conclusion, the court noted that one of the Commission’s core regulatory responsibilities is to ensure that public utilities provide “safe, reasonable and adequate service” to customers.  The court found that the Commission had explicitly declined to decide "that smart meter technology is not a credible threat to the health and safety of CMP’s customers".  On that sole ground, the court vacated the portion of the Commission’s dismissal of the customer complaint that was directed at CMP and addressed health and safety concerns.

So what does the court's ruling mean in practical terms? CMP has already installed about 600,000 smart meters across its service territory, and has only about 2,000 smart meters left to install. The Commission is undoubtedly reviewing the court's order and has scheduled a deliberative session for next Tuesday, July 24, at 10:00 a.m.

Hydropower Regulatory Efficiency Act of 2012

Tuesday, July 17, 2012

Last week the U.S. House of Representatives unanimously passed H.R. 5892, the Hydropower Regulatory Efficiency Act of 2012. The bill, introduced by Rep. Cathy McMorris Rodgers of Washington, is designed to implement a variety of measures promoting the production of electricity from small and conduit hydropower projects.

The bill opens with a series of Congressional findings regarding hydropower in the U.S.:
Congress finds that--

(1) the hydropower industry currently employs approximately 300,000 workers across the United States;

(2) hydropower is the largest source of clean, renewable electricity in the United States;

(3) as of the date of enactment of this Act, hydropower resources, including pumped storage facilities, provide--
(A) nearly 7 percent of the electricity generated in the United States; and
(B) approximately 100,000 megawatts of electric capacity in the United States;

(4) only 3 percent of the 80,000 dams in the United States generate electricity, so there is substantial potential for adding hydropower generation to nonpowered dams; and

(5) according to one study, by utilizing currently untapped resources, the United States could add approximately 60,000 megawatts of new hydropower capacity by 2025, which could create 700,000 new jobs over the next 13 years.
The bill goes on to implement a series of regulatory changes, including:
  • Increasing the maximum size of hydro projects eligible for exemption from licensing from 5 MW to 10 MW 
  • Promoting conduit hydropower – projects involving adding generation to existing pipes and canals
  • Allowing FERC to extend a 3-year preliminary permit by up to 2 more years if the permittee worked diligently and in good faith
  • Requiring FERC to investigate the development of a 2-year licensure process for developing hydropower at currently-unpowered dams and closed-loop pumped storage projects, and if feasible test the shortened process on one or more pilot projects
  • Requiring the U.S. Department of Energy to study the potential of pumped storage to back up intermittent renewables and provide reliability, and to produce new hydropower from existing conduits
H.R. 5892 is now before the Senate for its consideration.

Corn, ethanol, drought, and demand

Thursday, July 12, 2012

Corn plays an important role in current United States transportation fuel policy - but environmental and economic factors are putting the pinch on corn ethanol producers.

The U.S. Renewable Fuel Standard program requires transportation fuel sold in the United States to contain at least a minimum volume of renewable fuel.  This renewable fuel is generally ethanol, produced by fermenting sugars contained in plant feedstocks like sugar cane and sugar beets, or sugars produced by converting plant-based starches like corn starch.  The program's goals include reducing greenhouse gas emissions from the transportation sector, reducing petroleum imports, and encouraging the development and expansion of the domestic renewable fuels sector.

In the U.S., more than 95 percent of operating ethanol plants reportedly use corn starch as their feedstock.  According to the U.S. Department of Agriculture, U.S. farmers planted 96.4 million acres of corn this year, the highest corn acreage since 1937.  Favorable field conditions this spring led to the quickest planting pace on record, with nearly all of the corn planted by May 20 and plants emerged by June 3.

This summer's high temperatures and widespread drought conditions - with nearly 56% of the area of the 48 contiguous states experiencing drought - have hurt the U.S. corn crop, resulting in reduced estimates for this year's crop.  This anticipated reduction is driving corn prices up, with the commodity trading at over $7 per bushel (contrast a 2007 U.S. Energy Information Administration analysis of transportation biofuels assuming corn prices of about $2 per bushel).  This price increase is cutting into ethanol producers' bottom line.

At the same time, transportation fuel consumers are driving less.  Between increased fleet efficiency prompted by both governmental mandates and a natural desire to cut costs, and the overall slowdown in the national economy, overall demand for ethanol fuel has not grown at the pace previously projected.

According to Reuters, the average ethanol plant operating in Illinois is currently losing 32 cents on every gallon it produces.  As a result, many ethanol plants are running below their production capacity, and several have announced planned closures.  EIA data shows that ethanol production dropped 4% last week to 821,000 barrels per day, the lowest production rate since July 23, 2010.

Proponents of blending ethanol into transportation fuels point to its nature as a renewable biofuel, lower cost than gasoline, and ability to be produced domestically.  Critics question the wisdom of converting a potential food crop into an energy commodity, as well as the economic and environmental consequences of current pro-ethanol policies.  Whatever the ultimate outcome, the climatic and economic conditions affecting the corn ethanol industry may be calling into question the sustainability of the current system.

Electricity and natural gas market links

Wednesday, July 11, 2012

Concerns over the increasing interdependence of natural gas and electricity markets in the United States have prompted federal regulators to schedule a series of technical conferences on the subject for next month.

In recent years, natural gas has increased its share of the energy mix used to generate electricity.  Usage of coal, historically the dominant fuel used to generate electricity, is declining, while natural gas pricing is historically low.  This shift to increased reliance on natural gas is also driven in part by the growth of intermittent renewable energy resources like wind which may need natural gas to back them up when the wind isn't blowing.

At the same time, investigations into the blackouts and reliability problems like those affecting Texas and the Southwest in February of 2011 suggest that a lack of coordination between the electricity and gas industries may be partly responsible for the outages.

On February 3, 2012, Federal Energy Regulatory Commission Commissioner Philip Moeller issued a letter posing a series of questions concerning gas-electric interdependence.  His questions included what role the FERC should play in overseeing better coordination between the two industries, what regional differences might affect this coordination, and differences in how electricity and gas are traded in their respective markets.

In response to Commissioner Moeller's letter, a variety of stakeholders submitted comments.  Many commenters suggested that significant regional differences exist in both how markets operate and how their coordination could be improved.

As a result, the FERC has scheduled a series of regionally-oriented technical conferences for August:
  • Central (generally the areas controlled by Midwest Independent Transmission System Operator Inc. (MISO), Southwest Power Pool, Inc. (SPP) and Electric Reliability Council of Texas (ERCOT)), to be held August 6, 2012, in St. Louis, MO
  • Northeast (generally the area controlled by ISO New England, Inc.), to be held August 20, 2012, in Boston, MA
  • Southeast (generally the areas controlled by Southern Company, Duke and Progress Energy, TVA, as well as other areas south of PJM Interconnection, L.L.C. (PJM) and East of SPP and ERCOT), to be held August 23, 2012, at FERC headquarters in Washington, DC
  • West (generally the Western Interconnection), to be held August 28, 2012, in Portland, OR
  • Mid-Atlantic (generally the areas controlled by New York Independent System Operator Inc. (NYISO), PJM and related areas), to be held August 30, 2012, at FERC headquarters in Washington, DC
FERC anticipates that each conference will be organized as a roundtable discussion regarding the sharing of information and communications, scheduling, market structures and rules, and reliability concerns.  The Commission has encouraged those interested in attending a conference to register by July 19, 2012.

Marcellus shale gas drilling slows

Tuesday, July 10, 2012

Natural gas drilling activity has declined in parts of the Marcellus Shale formation under Pennsylvania and other eastern states, largely as a result of low gas prices.  These prices in turn are largely the result of significant increases in the available supply of recoverable natural gas made possible by horizontal drilling techniques and hydraulic fracturing or fracking.  As a consequence, many natural gas producers are focusing on areas of shale rich in both gas and natural gas liquids.

The Marcellus Shale, a layer of ancient marine sediment rich in organic material and extending beneath Pennsylvania, Ohio, West Virginia, New York, and Maryland, is believed to be one of the world's largest natural gas fields.  In 2008, drilling activity in the Marcellus Shale began to increase significantly, as these newer drilling techniques and increases in the price of other fuels like oil made the shale gas economically feasible to recover.  (Compare this map of Marcellus shale drilling activity in Pennsylvania from 7/25/2008 to this map of permits issued as of March 9, 2012.)  As of this spring, Pennsylvania alone had issued 11,772 permits for vertical and horizontal gas wells in the Marcellus formation.

One result of the expansion of shale gas production is a significant decrease in the price of natural gas.  Since 2008, natural gas prices at the Henry Hub in Louisiana (where gas as a commodity is typically priced) have fallen from over $12 per million British thermal units (MMBtu) to as low as $2 per MMBtu.  Other factors have played a role in this price decline, such as a mild winter with lower-than-expected heating demand and the overall economic slowdown, but the increase in supply due to shale gas production is viewed as a major cause of the price decline.

Now, one of the effects of the price decline is a decrease in natural gas drilling activity.  This decrease is particularly marked in areas where the shale produces "dry gas", or natural gas that is primarily methane and is low in so-called natural gas liquids.  Natural gas liquids -- hydrocarbons other than methane that are extracted when natural gas is processed in a natural gas treatment facility -- include ethane, propane, and butanes.  These natural gas liquids are important feedstocks for the production of many chemicals and plastics, and add value to the natural gas produced from "wet" shales.

Where shale gas contains significant amounts of natural gas liquids, production appears steady or increasing, while gas producers in areas with lower amounts of natural gas liquids are now saying that they are having a hard time making money off gas alone.  If this trend continues, areas of dry gas like much of the known portions of the Marcellus Shale may continue to see a slowdown in drilling activity while producers focus on areas rich in natural gas liquids.

FERC considers bulk electric system definition

Thursday, July 5, 2012

In a society dependent on electricity for many essential and desired services, maintaining the reliability of the electric grid bears increased importance.  From hospitals and home heating to business operations, "keeping the lights on" has become a matter of national significance.  How electric reliability is regulated is the subject of an ongoing administrative case noticed in today's Federal Register.

At the federal level, chief regulatory responsibility for electric reliability falls on the Federal Energy Regulatory Commission.  Following the August 2003 blackout, when 50 million people lost power in the U.S. and Canada, Congress authorized the creation of an “electric reliability organization” to manage the reliability of the North American bulk power system.

Today, that organization is the North American Electric Reliability Corporation (NERC).  NERC's mission is to ensure the reliability of the North American bulk power system.  To achieve this mission, NERC establishes and enforces reliability standards for the bulk power system.

In 2010, FERC issued Order No. 743 (104-page PDF), which ordered NERC to revise its definition of the "bulk electric system" -- a specific subset of the bulk power system.  Historically, that term has been defined differently by each of each of eight regional entities.  In Order No. 743, FERC recognized concerns arising from inconsistencies among these regional definitions, and recommended replacing the regional entities' discretion to define the "bulk electric system" with a bright line threshold.  This bright line standard would include all facilities operated at or above 100 kV except defined radial facilities.  FERC also recommended that NERC adopt an exemption process and criteria for removing facilities from NERC's authority that are not necessary for operating the interconnected transmission network.

After stakeholder input, NERC proposed a core definition that included all transmission elements operated at 100 kV or higher and real power and reactive power resources connected at 100 kV or higher, while establishing an express exclusion for facilities used in the local distribution of electrical energy as well as certain behind-the-meter generation facilities.  NERC also proposed changes to how entities targeted for inclusion in its compliance registry as part of the bulk electric system may seek an exception from regulation.

FERC proposes to adopt NERC's proposal, and has issued a Notice of Proposed Rulemaking (or "NOPR", a 94-page PDF) on the issue.  In the NOPR, FERC seeks public comment on several issues, including whether NERC's proposal properly distinguishes between local distribution and transmission, and whether NERC's proposed procedures for seeking an exclusion from registration are sufficient.  Comments are due to FERC by September 4, 2012.

Energy projects installed in May 2012

Tuesday, July 3, 2012

A report released this week by federal energy regulators documents the composition of additions to the U.S.'s portfolio of electricity resources.  The May 2012 Energy Infrastructure Update released by the Federal Energy Regulatory Commission's Office of Energy Projects provides a summary of newly-built and expanded electric generation facilities.  This snapshot of what happened in May 2012 illustrates trends in the electric industry, including a focus on renewable energy and natural gas in project development.

According to the report, 561 megawatts of new or expanded electric generation capacity came online in May 2012.  Of this new installed capacity, the largest share -- 228 MW -- came from wind.  Most of this new capacity comes from a single project, E.ON Climate & Renewables North America, LLC’s Magic Valley Wind Farm I in Texas.  The Magic Valley I project is comprised of 112 Vestas V100 1.8-MW turbines, for a total nameplate capacity of 202 MW.

The second-largest resource class of new generation capacity in May 2012 comes from biomass, with 166 MW of new biomass capacity installed in May.  As with wind, Texas hosts the bulk of this new  capacity.  The largest new biomass project is a 100 MW wood-fired plant built in Nacogdoches County, Texas, by Southern Company, financed in part through a long-term power purchase agreement with Austin Energy to buy the power.

Solar-powered generation provides the third-largest class of capacity newly installed in May 2012.  Eleven new projects came online in May, totaling 149 MW of new capacity.  The largest of these is Enbridge Inc.’s 50 MW Silver State North Solar Project.  This project, located in Clark County, Nevada, is the first utility-scale solar facility built on federal land managed by the Bureau of Land Management.  Its output will be sold to NV Energy under a long-term PPA.

Together, these three renewable resources -- wind, biomass, and solar -- represent 543 out of the 561 MW installed in May 2012. Other fuels like coal and natural gas played a relatively minor role in terms of new capacity installed in May.  Nevertheless, the year-to-date cumulative data shows that natural gas powers the largest share of projects installed in 2012 -- 2,811 MW out of the 6,225 MW installed so far in 2012.

Transmission costs up, energy costs down

Monday, July 2, 2012

The cost of electric transmission and distribution service in Maine is going up, at the same time that the cost of electric energy is going down.  What this means has implications not only for Maine but for all societies seeking to reduce the cost of electricity.

The cost of electricity to consumers can generally be broken down into two categories: energy and transmission and distribution service.  Electric energy charges represent the cost of the useable electricity that flows through an end-user's meter.  Transmission and distribution service charges, sometimes called "wires charges" or "delivery charges", represent the cost of delivering that amount of energy to the consumer.

In many states, vertically-integrated utilities both generate and deliver the energy.  Other states have restructured or deregulated their electric generation business; in these states, electric utilities deliver energy produced by non-utility generators.  Consumers in restructured states are usually free to select their own competitive electricity provider, whose energy will be delivered over the wires operated by the monopolistic local utility.  Because utilities continue to have a duty to serve all customers, if a consumer doesn't choose a competitive generation source, the utility will provide energy through a default service or "standard offer".

Maine is an example of a restructured state.  The state Public Utilities Commission regulates transmission and distribution utilities and their rates.  Effective July 1, the wires charges for Maine's two largest utilities -- Central Maine Power Co. (CMP) and Bangor Hydro Electric Company (BHE) -- went up.  On average, CMP customers' rates show an increase of 7.1% for the delivery portion of the bill; BHE customers' delivery rates increased 4.5%.  According to the Maine PUC's press release, the major driving force behind these increases are significant increases in the utilities' federally regulated transmission rates: a 19.6% increase for CMP and a 12% increase for BHE.  These transmission rate increases are in turn driven by multi-billion dollar expansions of and upgrades to the New England transmission grid.

At the same time, average energy prices in New England decreased by 7% between 2010 and 2011, largely as a result of cheaper natural gas supplies and reduced demand for electricity.  These energy price declines translated into decreases in the standard offer service delivered by these two utilities, about 25% to 35% lower than prices one year ago.

These twin forces -- increased investment in the transmission grid and reduced electric energy costs -- are not unique to Maine, but exert themselves in a number of regions of the United States.  One net result of these changes is a shifting of consumer costs away from energy and onto wires charges.  The cost of transmission and distribution service thus plays an increasing role in driving customers' electricity costs.  Given this shift, efforts to reduce the cost of electricity to consumers may find the most fertile ground in ensuring that transmission development is efficient, and that utility developers earn a rate of return on their investment that is fair, or in federal regulators' terms, "just and reasonable".