EPA regs and electric grid reliability

Debate is ongoing about the effect of new environmental regulations on the U.S. electric grid.  Some worry that tighter environmental controls will force certain electric generators to shut down, driving up the cost of electricity or putting electric reliability at risk.  Others believe that the grid's integrity can be maintained, and that the new regulations are necessary to protect human health and the environment.

Support for the concerned side of the equation comes from a recent report by the North American Electric Reliability Corporation.  NERC is the nation's electric reliability organization, charged with ensuring the reliability of the North American bulk power system.  In NERC's 2011 Long-Term Reliability Assessment (559 page PDF), NERC notes that recent and future environmental regulations may force the early retirement of a significant portion of the nation's coal-fired generating plants.  These regulations include the recently-finalized Cross-State Air Pollution Rule, plus rules under development governing utility plants' water intakes and air emissions.  According to NERC's report, EPA's new cooling water intake structures and mercury and air toxics standards rules "may significantly affect bulk power system reliability depending on the scope and timing of the rule implementation and the mechanisms in place to preserve reliability."

At the same time, others observe that NERC's report assumes multiple worst-case scenarios and ignored the health and environmental benefits of the rules.  After reviewing a near-final draft of the NERC report, EPA itself wrote NERC a letter (4 page PDF), stating "it appears likely your report may contain ... faulty characterizations of our rules."  EPA pointed to several flaws in NERC's analysis, including that NERC assumed generators would be forced to adopt the most expensive solutions immediately, rather than selecting the most cost-effective technologies for each facility.  EPA noted that the bulk of threatened plant retirements suggested in NERC's report would come from the cooling water intake regulations -- regulations which are still under development.  Finally, EPA pointed out that NERC's analysis appears to assume that no one tries to preserve grid reliability as the regulations begin to take effect, "an outcome that flies in the face of our 40 years of implementing the Clean Air Act and Clean Water Act."  Given the positive impacts of the regulations -- with the Cross-State Air Pollution Rule alone projected to prevent 34,000 premature deaths and 400,000 cases of aggravated asthma per year -- EPA defended their value and refuted NERC's analysis.

Reliability of the grid is important, enough so that the Federal Energy Regulatory Commission convened a technical conference yesterday and today to discuss grid reliability and policy.  While that proceeding may result in interim orders or changes to policy, it may take years for the environmental regulations to both take effect and to impact generating plants.  At the same time, generators are keeping a close watch on federal environmental regulation as it develops.

Google reduces renewable research

In recent years, Google has branched out from its core internet business to work on reducing the cost of renewable energy -- but now appears to have turned away from its renewable research efforts.

Here's a quick recap of some of Google's energy plays.

• In February 2010, Google received market-based rate authority, a key federal approval to allow it to sell electricity at wholesale in the U.S. markets.  Google stated that the Federal Energy Regulatory Commission's approval would allow it to hedge its energy procurements more effectively.
• In April 2010, Google joined with 46 other companies supporting smart grid technology in asking President Obama to help consumers access real-time information about their electricity usage.
• In July 2010, Google agreed to buy electricity from a NextEra affiliate's wind generating facility in Iowa to help power its data centers.
• In October 2010, Google invested in underwater transmission lines to transmit power from offshore wind turbines to the mainland, including a 350-mile backbone line from Virginia to New Jersey. 
• In April 2011, Google invested up to $168 million in BrightSource Energy's 392 MW Ivanpah solar project in California.

In addition to these activities, Google launched its "Renewable Energy Cheaper than Coal" initiative.  This program included engineering research and development to reduce the cost and water consumption of concentrating solar plants like Ivanpah.  Now, Google has announced that it has "retired this initiative", while reaffirming its investment in Ivanpah and its green energy procurement.

What will the future hold for Google?  Google it.

Tide Mill Institute event a success

I was very pleased to attend this past weekend's Tide Mill Institute conference. The Tide Mill Institute describes its mission as "to advance the appreciation of tide mill history and technology by encouraging research, by promoting appropriate re-uses of former tide mill sites and by fostering communication among tide mill enthusiasts." Here's a link to the conference website: http://www.tidemillinstitute.org/23.html My presentation compared tidal power projects past and present, looking at project economics, law and regulation. Interesting, many of the judicial opinions about tide mills from centuries past address concerns still expressed about tidal power projects. How will a given project affect water quality? Neighboring property? Fisheries and navigation on? Long before regulatory agencies or specific environmental statutes, tide mills effectively faced regulation in the form of court orders over lawsuits. Today, a host of agencies has regulatory authority over the development and operation of tide mills and tidal electric generation. It was great to meet so man people interested in the past, present and future of tidal energy.

Maryland dam faces sedimentation threat

In September 2011, Tropical Storm Lee caused flooding in the mid-Atlantic region.  The Susquehanna River rose far above its banks, causing disruptive floods in Pennsylvania and Maryland.  Near the river’s mouth into Chesapeake Bay, massive flooding threatened to breach the 572-megawatt Conowingo Dam.

With its flood gates wide open, the dam survived the flooding.  At peak flows, about 7 million gallons flowed through the dam every minute.  That water transported millions of tons of sediment from the Susquehanna watershed out into the bay, along with large amounts of trash and debris.

The impacts of the flood are still being assessed.  Under typical operations, the dam builds up about 2 million tons of sediment every year, or about two-thirds of the Susquehanna River's total sediment burden.  (Compare the dams currently being removed from the Elwha River in Washington, which had trapped an estimated 24 million cubic yards of sediment.)  Overall, four dams on the Susquehanna might hold up to 280 million tons of sediment.

While Lee removed several years' worth of sediment from the Conowingo Dam, more sediment builds up every year.  The Army Corps is concerned that the Susquehanna River dams have nearly reached their full capacity to hold sediment, and is launching a project to study what could be done, such as sediment dredging or remediation.

Headwater benefits charges affect hydropower projects

Suppose you own a federally-licensed dam and hydroelectric generation facilities on a river.  The amount of electricity you can produce is determined by factors including how much water is flowing through your turbines every second and the dam’s “head”, or effective height through which that water falls.  Over an entire year, the amount of power you can produce is also affected by how much water can be stored in the watershed above your dam, and how well you can regulate the flow of water through your turbines.  For example, if you can impound more floodwaters upstream instead of spilling excess water over the dam, you can maintain maximum flows through your powerhouse for a longer period of time than you otherwise could.

Now suppose someone else builds a dam upstream from your site that enables better storage and regulation of water flows through the river.  Setting aside any environmental impacts from that change in flow, one upside of the improved flow regulation is that you can produce more power at your dam thanks to the upstream improvements.

Under the Federal Power Act, you may be required to reimburse that upstream dam owner for an equitable part of the benefits you receive from its improvements.  Federal hydropower licenses typically include a provision requiring the licensee to reimburse the owner of an upstream improvement for these headwater benefits.

Under the Commission’s regulations, headwater benefits charges can be calculated using an “energy gains” methodology.  This analysis includes an assessment of the difference between the number of kilowatt-hours of energy produced at a downstream project with the headwater project and that which would be produced without the headwater project.  Alternatively, dam owners may negotiate an agreement on headwater benefits charges and present it to the Commission for approval as a settlement offer.

Renewable demands drive billions in transmission investment

As demand for renewable electricity increases, utilities are proposing new transmission lines to connect the new crop of electric generation projects to consumer markets.  Given the scale of these projects, and because renewable power projects are often sited far from the cities and industrial sites where the electricity will be consumed, the proposed transmission lines can come with a significant price tag.  For example, the Northern Pass project - a proposed high-voltage DC transmission line capable of carrying 1200 megawatts of power from Quebec to New Hampshire - is projected to cost $1.1 billion. These costs, and who must pay them, can generate as much controversy as siting the route for the transmission lines.

Another major high-voltage direct current transmission line has been proposed by Rock Island Clean Line LLC.  The Rock Island Clean Line would run about 500 miles from northwestern Iowa into Illinois, where it would connect with the mid-Atlantic regional grid operated by PJM Interconnection.  The proposed line would be positioned to collect electricity produced by wind power facilities in the eastern parts of South Dakota and Nebraska as well as the western parts of Iowa and Minnesota.  This power could be delivered into Illinois, either to satisfy that state's renewable portfolio standard or for further transmission throughout the mid-Atlantic region.  Proponents of the line also claim that it would reduce transmission constraints between the Midwest ISO and PJM grids, as well as reducing wholesale energy prices in Iowa and Illinois.

The price tag for the Rock Island Clean Line project is projected to be $1.7 billion.  While the current project is based on the assumption that the electricity flowing over the line would come from wind generation, there is no guarantee that the resource mix will be as expected.

FERC releases report on demand response

Demand response is an innovative smart-grid approach to meeting society's electricity needs. As customer demands on electric grids increase, the generating resources needed to meet higher and higher peak demands are typically more expensive to run and have more adverse environmental impacts.  In essence, demand response means covering electric load by having individuals or companies agree to temporarily cut back on electricity consumption in response to peak demand conditions.  When customers are willing to provide this service at a lower cost than generation, demand response can be a decentralized, crowd-sourced alternative to peaking power plants.

U.S. federal regulatory staff released a report this week assessing the nation's demand response and smart  meter resources.  The Federal Energy Regulatory Commission staff report is the sixth annual briefing since the enactment of the Energy Policy Act of 2005, which contained provisions promoting the development of demand response resources and markets.

The report notes that more and more customers have access to the kind of advanced meters that facilitate demand response participation.  These smart meters can not only measure instantaneous electricity demand, but typically report back to a utility automatically using radio frequency communications.  Since 2009, advanced meters have risen from 8.7% to a 13.4% share of all installed meters.  The report suggests that the actual penetration rate of advanced meters may be even higher if it includes meters that are installed but whose advanced features have not yet been activated.

The report also notes that in 2010, the grid operators it surveyed had a total of 31,702 MW of demand response resource potential, or enough to cover about 7% of the total 2010 peak demand.  Regional demand response capacities ranged from as low as 2.3% of peak load in the Electric Reliability Council of Texas to as high as 10.5% in the mid-Atlantic region's PJM Interconnection.  The report noted that demand response resourcs "made significant contributions to balancing supply and demand during system emergencies" in 2011.

Virginia considers net metering and utility standby charges

Virginia, like many states, allows grid-connected electricity customers to use customer-sited generation to offset its electric bill.  This practice is called net metering.

Virginia regulators are now considering a proposal by utility Dominion Virginia Power to impose two “standby” charges on net-metered solar photovoltaic systems larger than 10 kW.  The policy questions raised by this case appear in other contexts where incentives for clean, distributed generation run up against utility ratemaking considerations.  Utilities typically argue that they need to allocate costs fairly among their customers, while customer-sited generation advocates point to both the value of distributed generation and the array of incentives promoting customer-sited generation.

In June 2011, the Virginia legislature enacted House Bill 1983, directing Dominion to allow residential customers to net meter solar photovoltaicsystems between 10 kW and 20 kW.  Dominion responded by petitioning the Virginia State Corporation Commission (SCC) for approval of tariff changes that it argued are necessary to reflect its actual costs in supporting these customers’ peak loads.  The utility proposed to add monthly standby charges for transmission and distribution service based on each net-metered customer’s highest 30-minute demand.

Utilities often argue that their fixed costs in serving net-metering customers – maintaining wires, transformers, and other infrastructure – are the same as if the customers had no generation.  If a customer can be self-sufficient most of the time, the utility grid must still be of a sufficient size to deliver the customers’ peak demand when it is needed, such as when customer-sited generation fails.  Dominion requested approval of its standby charges to ensure fair cost allocation among customers.

Distributed generation advocates, on the other hand, argue that the standby charges would result in overcharging net-metered customers.  In Dominion's case, a witness for the Maryland, District of Columbia and Virginia Solar Energy Industries Association testified the standby charge would result in higher charges for a net-metered customer than a regular customer consuming the same amount of grid-purchased electricity.  The witness also testified that net-metering customers should receive credits for generating cost-effective energy, and for reducing the utility’s transmission line losses.  Diverse distributed generation may also reduce utilities’ distribution costs.  The solar association argued that Dominion's standby charges ignored these benefits, and would chill distributed solar development in spite of Virginia's net-metering policy.

The Virginia State Corporation Commission held a hearing on Dominion's request last week, and is expected to issue an order resolving the matter.

Biofuels power first commercial airline flight

Today marks the first U.S. commercial airline flight powered by biofuels.  United Airlines has selected a Boeing 737-800 for the route from Houston to Chicago.  The plane will be powered by Solajet, a fuel blend of 60 percent petroleum-based jet fuel and 40 percent biofuel produced by California-based algae producer Solazyme.


Biofuels appear poised to play an increasing role in the transportation sector.  Biofuels have traditionally included liquid fuels like ethanol (derived from corn or cellulosic sources) and biodiesel.  Biofuels typically rely on plants or algae to convert solar energy into chemicals that can be refined and modified to produce usable fuels.  The wood (biomass) burned in hearths and stoves around the world represents a very basic biofuel, but today's advanced biofuels can involve significantly more technology.  The U.S. Department of Energy is funding research and development efforts to produce "drop-in biofuels", which can be  used as additives or even replacements for liquid fuels like gasoline, diesel and jet fuels -- without requiring consumers or distributors to modify their engines and fuel distribution networks.

United Airlines is not the only carrier to take its biofuels experimentation live this week.  On Wednesday, Alaska Airlines will fly two commercial flights from its bases in Seattle and Portland, Oregon, to Washington, D.C.  Alaska Airlines' jets will be powered by a fuel blend composed of 20% biofuels from used cooking oil.  Alaska Airlines chose Dynamic Fuels as its supplier; Dynamic Fuels is a joint venture between food product giant Tyson Foods and synthetic fuel producer Syntroleum.

Presidential permits for cross-border energy facilities

Presidential permits for the import and export of energy resources across the United States' borders are critical to the development of cross-border energy facilities.

Millions of dollars of energy resources flow across the United States' borders every day.  Trade in energy resources with Canada and Mexico accounts for the bulk of these transactions.  Canada is the single largest foreign supplier of energy to the United States, providing about 20% of U.S. oil imports and 18% of U.S. natural gas imports according to the U.S. State Department.  Canada and the United States share an integrated electricity grid and provide all of each other's electricity imports.  Today and tomorrow, members and guests of the New England - Canada Business Council are meeting in Boston to discuss this close relationship.

Facilities spanning the border -- whether pipelines for oil or natural gas or transmission lines for electricity -- can only be built and operated once a federal approval called a "presidential permit" has been obtained.  Since a 1968 Executive Order, presidential permits have been issued by the State Department.  Presidential permits cover not only the facilities themselves, but also the commodities (oil, gas, electricity) transmitted over those facilities.

For example, the proposed Keystone XL pipeline from Canada to Texas will require a presidential permit.  In today's news, President Obama is reported as saying that he will be the one to make the final decision on whether TransCanada will obtain its permit.