FERC grid modernization session

U.S. federal energy regulators convene tomorrow to discuss modernization of the nation’s electric power grid.

Recent years have brought significant changes in technology and the ways we use energy.  From distributed energy resources like solar panels to a variety of "smart grid" applications, society has new tools that may be able to improve the nation's energy sector.  As a result, state and federal energy regulators are considering "grid modernization."  Issues in play can include whether improvements to the nation’s electric power grid are appropriate, and if so, how to fund them.

For several years, the Federal Energy Regulatory Commission has considered grid modernization issues.  Now, the Commission has scheduled a grid modernization event for tomorrow.

At the Commission's April meeting, it will hear from representatives from the U.S. Department of Energy, including Patricia A. Hoffman, assistant secretary for the Office of Electricity Delivery and Energy Reliability, and Roland Risser, acting deputy assistant secretary for Renewable Power.  The Energy Department will also offer panelists from its National Renewable Energy Laboratory, Pacific Northwest National Laboratory, Idaho National Laboratory, Sandia National Laboratories, and Lawrence Berkeley National Laboratory. 

Following the FERC meeting, the panelists will be available for a post-meeting information session on the work of the Grid Modernization Laboratory Consortium.  Panelists are expected to discuss devices and integrated systems, sensing and measurement, system operations, control and power flow, design and planning tools, security and resilience, and institutional support.

Maine PUC considers NTA coordinator

Maine utility regulators have launched an investigation into the designation of a "Non-Transmission Alternative Coordinator."  The case could shape whether and how Maine coordinates alternatives to electric transmission line development.

Non-transmission alternatives or NTAs are smart grid programs and technologies that complement and improve operation of existing electricity transmission systems, deferring or eliminating the need for upgrades to the transmission system.  NTAs can an deliver improvements to the grid at a lower cost than some transmission projects.  Distributed generation, storage, and demand response can play roles in NTA projects.

In Maine, legislative policy supports selecting NTAs over transmission development if an NTA can meet an identified reliability need at a lower cost to consumers than the proposed transmission project.  But under current law, no single entity formally coordinates or is required to postulate alternatives to transmission development.

In previous cases, the Maine Public Utilities Commission has investigated the need for a smart grid coordinator, approved a non-transmission alternative pilot project in the Boothbay region, and considered the scope of what an NTA Coordinator might do.  From these dockets, a vision has emerged of the NTA Coordinator as an entity that would develop cost-effective alternatives to transmission projects.  Under this vision, the NTA Coordinator would address the policy and goals of the Maine's Smart Grid Policy Act to “improve the overall reliability and efficiency of the electric system, reduce ratepayers’ costs in a way that improves the overall efficiency of electric energy resources, reduce and better manage energy consumption and reduce greenhouse gas emissions.”

But key questions remain, including whether and how an NTA Coordinator will be designated, the scope of its functions and duties.  Another fundamental question is whether these functions will be performed by transmission and distribution utilities, or by some third party entity.

In a Notice of Investigation dated April 4, 2016, the Maine Public Utilities Commission opened its investigation into these questions.  The notice describes the proceeding as focused on one approach to economically optimizing the electric system between generation and transmission:

Specifically, through this proceeding, the Commission expects to address this legislative policy by (1) developing the framework for selecting a NTA Coordinator and (2) determining the scope of the NTA Coordinator’s functions and duties. The Commission will also resolve the question of whether a third party entity or the transmission and distribution (T&D) utilities should perform the NTA Coordinator functions. This investigation will also address the role of an Advisory Planning Committee (APC) and the process for NTA development both within a CPCN proceeding and for transmission and distribution projects that are not required to file a CPCN petition. Finally, an end-product of this proceeding will be either the contours of an RFP or that of a rate incentive proposal should the Commission determine that the utility and not a third party should perform the functions of an NTA Coordinator.

Along with the notice of investigation, the Commission also issued "Strawman" and "Process Chart" documents for comment.

The notice set deadlines for filing petitions to intervene by April 21, 2016, and for comments on the Strawman and Process Chart by April 28, 2016.  An initial case conference was scheduled for May 12, 2016.

Maine explores non-transmission alternatives coordinator

Should Maine designate an entity to coordinate the development of lower-cost alternatives to new electric transmission lines?  The Maine Public Utilities Commission has opened an inquiry to obtain comments on the role of a non-transmission alternative (NTA) coordinator and the parameters for procuring the services of an NTA coordinator.

Modern society counts on electric utilities and power plants to supply consumers with electricity.  As consumer needs and plant economics change over time, utilities have traditionally looked to new infrastructure like transmission lines to meet new needs.  But in some cases, transmission development may not be the cheapest or best way to meet consumer needs; rather, "non-transmission alternatives" such as distributed generation, energy efficiency or microgrids may be able to achieve the same ends for a lower total cost.

Grid modernization -- and the tools needed to manage the process efficiently -- can be controversial.  By order dated May 11, 2015, the Maine Public Utilities Commission declined to designate a "Smart Grid Coordinator" to provide a broad array of services to the state, on the grounds that that the record before it did not support a finding that designate a coordinator to provide all these services was in the public interest.

But the Commission indicated interest in designating someone to provide the services of marketing, implementing, and possibly operating non-transmission alternatives.  To that end, the Commission found "there is the potential for benefits from an entity that has the relevant expertise and a commercial interest in the successful development and implementation of NTAs" -- provided that the entity can deliver its services in a way that provides value to ratepayers.

By a June 30 Notice of Inquiry, the Commission initiated the next phase of its exploration of designating an NTA coordinator.  The Commission requested comment on issues it had previously identified in its May 11 order as requiring further factual development to enable the Commission to determine whether it is in the public interest to designate an NTA coordinator:

1. What duties should be included in the scope of services offered by an NTA coordinator?
2. Should T&D utilities be allowed to bid on an NTA RFP and if so should such services be provided through an affiliate? 
3. If an RFP were seeking proposals for having a non-utility entity operate an NTA in a manner consistent with reliability and cyber security standards, how would the incremental costs to operate the NTA be determined?
4. What type of pricing structures should be considered in developing the RFP?
5. What factors should be considered in bid evaluation?
6. What should be the term of the NTA coordinator contract?
7. What entities should be the counterparties to the contract?
8. What enforcement mechanisms should be included in the contract?
9. What type/amount of financial security should be required?

The Commission also invited comment on any other issues relevant to its consideration of designating an NTA coordinator.  The Commission requests that comments be filed by July 21, 2015.  After comments are received, Commission staff will schedule a meeting to discuss the comments and discuss next steps in the development of a request for proposals.

FERC Order 676-H adopts NAESB standards

Last week the Federal Energy Regulatory Commission issued Order No. 676-H, adopting and incorporating into its regulations most of the latest version of a set public utility business practice standards and communications protocols developed by the North American Energy Standards Board (NAESB).  While most of the NAESB standards will now become mandatory and enforceable, to enable smart grid innovation the Commission posted NAESB's five Smart Grid standards as non-binding guidance.

Industry standards enable cooperation and communication, and can lead to more efficient and competitive markets.  Formally known as Version 003 of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by NAESB's Wholesale Electric Quadrant (WEQ), the newly adopted standards represent the latest evolution of NAESB's consensus-based standards for public utilities.  NAESB is an ANSI-accredited non-profit standards development organization formed to develop and promote business practice standards that promote a seamless marketplace for wholesale and retail natural gas and electricity. Since issuing Order No. 676 in 2006, the FERC has incorporated elements of NAESB's standards into its regulations.

While the FERC made most of the NAESB standards mandatory, it decided to include NAESB's smart grid standards only "informationally, as guidance."  While FERC noted that the smart grid standards have value and should be adopted by public utilities, it ultimately agreed with utility trade group Edison Electric Institute and the ISO/RTO Council that NAESB's five Smart Grid standards should neither be incorporated into formal federal regulation nor be enforceable and mandatory.  Notably, as prepared by NAESB the Smart Grid standards are meant to be optional and informative, not prescriptive or restrictive, and could prove difficult to enforce.

Thus to "encourage further developments in interoperability, technological innovation and standardization", the FERC chose to include NAESB's five smart grid standards in Order No. 676-H as guidance, but not to incorporate them into its formal, enforceable regulations.

Through Order No. 676-H, the FERC hopes to improve business practices and interoperability among public utilities.  The order also shows an intent to foster smart grid technologies, without stifling their development through overly prescriptive or unenforceable regulations.  Will Order 676-H usher in a new era of smart grid and utility cooperation?

Maine utility launches time-of-use rates

A Maine electric utility has launched a program to offer residential consumers rates that vary depending on whether the consumption occurs during times of peak demand on the electric grid.  Central Maine Power Company's residential time-of-use rates are designed to encourage consumers to shift their use of electricity-intensive equipment to off-peak hours, generally between 8:00 p.m. and 7:00 a.m. and on weekends. How many customers will choose this option?  What effects will it have, both for the consumers opting in and for society as a whole?

Traditionally, electric ratepayers pay the same price for every kilowatt-hour of energy they consume, without regard to the time of consumption or to conditions on the grid.  But the cost of producing a given kilowatt-hour of electricity depends on factors including the portfolio of generators operating at the time, as well as on the instantaneous demand for electricity in the overall regional market.  Because they are not directly exposed to the real-time price of power, consumers individually and collectively may not make efficiency choices about how much power they consume, and when they consume it.  For example, energy prices are typically lower at night, when demand is reduced, but consumers have not traditionally had any incentive to shift their consumption to lower-priced nighttime hours.  Some utilities have offered industrial and commercial businesses time-of-use rates to encourage efficiency, but most residential ratepayers have not had this option in recent years.

Central Maine Power now offers residential consumers the option to choose time-of-use rates.  Prices during peak hours will be about 15 percent higher than under the default rate schedule, with off-peak prices about 20 percent below the default rates.  The structure offers the opportunity for consumers to choose to shift heavy-consuming applications like air conditioning and heating to off-peak hours.  This could save these consumers money - but it would require them to modify their behavior, invest in new "smart" technology, or both.  Will consumers find the opportunity for savings to be worth these changes?

The current enrollment window is open through January 31, 2013.

NY releases Energy Highway Blueprint

This week New York Governor Cuomo released the New York Energy Highway Blueprint (12 megabyte PDF), the state’s plan to “rebuild and rejuvenate New York State’s electric power system and enable the state to meet the needs of a 21st century economy and society.”

The Blueprint outlines 13 recommended actions in four focus areas, including:

• Expand and Strengthen the Energy Highway: building $1 billion of new electric transmission totaling over 1,000 MW of capacity, develop reliability contingency plans for power plant retirements (including energy efficiency and demand response), and support flexibility in public power authority contracting
• Accelerate Construction and Repair: advance up to $800 million of investments in electric generation, transmission, and distribution, and advance up to $500 million of investments in natural gas distribution to reduce costs to customers and enhance reliability, safety, and emission reductions
• Support Clean Energy: execute new contracts for up to $250 million within the next year with renewable energy developers under the Renewable Portfolio Standard to leverage an additional $425 million in private-sector investment to build up to 270 MW, study NY’s Atlantic offshore wind resource, and repower 750 MW of inefficient power plants on Long Island
• Drive Technology Innovation: facilitate smart grid initiatives with the investment of up to $250 million

Nothing in the Blueprint is mandatory, but it appears to have significant political force behind it.  What will the Blueprint likely lead to?

One likely result is significant transmission development.  If this happens, the new transmission lines could enhance reliability and create opportunities for energy produced upstate or in rural areas to be transmitted to load centers like New York City.  Transmission line development typically involves significant construction work and related employment, but can be expensive.  How this transmission development will be paid for remains to be seen, and may not be resolved for several years.

Another area of interest involves the development of reliability contingency plans for power plant retirements.  The Indian Point nuclear plant, located about 30 miles north of NYC, is currently undergoing a relicensing proceeding before the Nuclear Regulatory Commission.  It is unclear whether either or both of the two reactors at Indian Point will be relicensed, meaning New York may need to secure replacement power by 2016 (or sooner).  The Blueprint recommends that contingency plans for partial or full retirement of the Indian Point plant include energy efficiency and demand response.

The Blueprint also includes plans to increase the availability of natural gas, including for the purpose of switching customers from oil to gas. The NY Department of Public Service is slated to issue a notice on natural gas expansion policies by the end of 2012. It is unclear how the program will split its focus between residential, commercial, and industrial customers, but it could help reduce the cost and environmental impacts of oil use in New York.

Overall, the Blueprint could result in the addition of up to 3,200 megawatts of additional electric generation and transmission capacity through up to $5.7 billion in private investments.  Over the upcoming months, state agencies and the New York legislature will consider the Blueprint, and whether and how it can be implemented.  At the same time, businesses are evaluating the Blueprint to see if it can help them develop renewable and traditional generation, transmission lines, energy efficiency, demand response, and other energy projects.

FERC seeks demand response standards

Demand response, an innovative strategy to ensuring the integrity of electric grids, is growing in popularity, prompting federal regulators to consider standardizing how demand response performance is measured.

Managing an electric grid entails ensuring a constant balance between electric generation and customer demand for electricity.  As customer demand rises, grid operators have traditionally called on more and more generating units.  In most markets, grid operators dispatch the lowest-cost units first to keep overall costs down.  As a result, generating units needed to meet peak demand tend to be more expensive than baseload generation.  Many peaking units also emit more pollutants per unit of energy than baseload units.

In a demand response program, customers can volunteer to be available to reduce their load during times of peak demand.  When done right, this reduction in customer demand can play much the same role as dispatching additional generation, but at a lower cost in dollars and environmental impacts.  Energy efficiency resources can also play a similar role.

The U.S. Congress and the Federal Energy Regulatory Commission have both recognized that demand response can be a decentralized, crowd-sourced alternative to peaking power plants.  Utilities and regional transmission organizations across the nation are implementing demand response programs.

As demand response grows in importance, the question of how to measure a customer's performance is important.  Different utilities and regions have adopted varying standards for how performance is measured.  In an attempt to standardize the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets, the FERC has proposed to amend its regulations to incorporate by reference the demand-side management and energy efficiency business practice standards of the North American Energy Standards Board.  NAESB describes itself as "an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities."

In its Notice of Proposed Rulemaking (29-page PDF), Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041, FERC states its hope that "[a]doption of these standards is intended to improve the methods and procedures used to accurately measure demand response and energy efficiency resource performance" and that their adoption should help regional grid operators "properly credit demand response and energy efficiency resources for their services".

Data center energy use, consolidation

Data centers - centralized locations where computer servers store and process information - play a key role in the function of society today.  Demand for data center capacity is growing, as more and more digital information is collected and used to refine our technological experiences.  For example, the growth of a smart electric grid relies in part on real-time data collection and analysis on a massive scale.

Data centers consume significant amounts of energy, primarily in the form of electricity.  Progress in computer energy efficiency has reduced data centers' electricity consumption per unit of capacity, but the overall growth of data center capacity means they consume more and more electricity every year.  Some data centers choose to buy renewable energy to serve their needs.  In addition, data centers typically need cooling capacity, creating additional energy demand.

Energy costs are driving some data centers to consolidate.  For example, many data centers in the U.S. serve federal agencies.  In 2010, the federal government began a major effort to consolidate data centers and close unneeded facilities.  The Federal Data Center Consolidation Initiative is designed to promote "Green IT" principles by reducing the overall energy and real estate footprints of government data centers and reduce data center costs.  If the initiative succeeds in its mission, it will shift investment towards more efficient technologies.  Another anticipated benefit of consolidating data centers is enhanced IT security.

As the initiative developed, agencies identified 3,133 federal data centers -- nearly three times as many as the nation's Chief Information Officer initially posited.  This growth is due in part to a broadened threshold for what counts as a data center, but also reflects imperfect information about total federal assets.  Of these facilities, the initiative now plans to close roughly 40%, or at least 1,200 data center locations.  According to the CIO's list, 525 will be closed by the end of 2012.

Many of the surplus facilities pruned off by the federal data center consolidation initiative may continue life in the private sector.  New owners may succeed if they can manage these data centers' energy consumption and benefit from participation in creative energy strategies like demand response or net metering distributed generation.

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.

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

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

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

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

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

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

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

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

March 16, 2011 - victory for demand response

The smart grid just got smarter.  Demand response -- when customers respond to signals about the scarcity of electricity by temporarily reducing their consumption -- is a key tool in efforts to reduce the cost of energy through the use of smart grid technology.  As a society (or as a grid), if we can reduce the peak amount of electricity being demanded, we can not only reduce the need for the most expensive marginal peaking generation units, but we can also reduce the need for expensive transmission lines.  Demand response thus benefits not only the person reducing consumption, but also all other ratepayers and the grid as a whole.  It is a key component of our transition to a smart grid.

On March 15, 2011, demand response took a big step forward through a Federal Energy Regulatory Commission ruling on how people should be compensated for demand response participation.  In Order No. 745 (116 page PDF), FERC ruled that organized wholesale energy market operators must pay demand response resources the market price for energy, known as the locational marginal price (LMP), when those resources have the capability to balance supply and demand as an alternative to a generation resource and when dispatch of those resources is cost-effective.

FERC noted that doing so is necessary to preserve and enhance the competitiveness of wholesale electricity markets, something FERC and Congress have promoted across the board.  For example, in the Energy Policy Act of 2005, Congress established a national policy of eliminating unnecessary barriers to demand response participation.  FERC has long held that active participation by customers in organized wholesale energy markets through demand response helps to increase competition in those markets, but had not previously required all organized wholesale markets to compensate demand response resources in the same manner.  For example, PJM has been paying the LMP minus the generation and transmission portions of the retail rate, while ISO New England has paid LMP only when prices exceeded a threshold level.  Even within a given market, the continual threat of policy changes resulted in a chilling effect on the full implementation and deployment of demand response.

FERC's Order No. 745 takes away this uncertainty.  FERC held that demand resources should be paid at market-based prices when two criteria are met: capability and cost-effectiveness.  First, the demand resources must have the capability to balance supply and demand as an alternative to a generation resource.  To be paid at market prices, demand resources must be effective at displacing the need for bringing additional generation online.  Second, the demand resources must be cost-effective alternatives to generation, based on a "net benefits test".  In essence, this test is satisfied when the overall benefit of the reduced energy price resulting from dispatching demand response resources exceeds the cost of dispatching and paying LMP to those resources.  If both of these criteria are satisfied, organized wholesale energy market operators must pay demand response resources the market price for their energy value.

Demand response has long had great potential to transform the way our power grids work.  To reach its full potential, people must be compensated fairly for the value they provide through interrupting their consumption of electricity.  With FERC's Order No. 745, that value has been established clearly.

February 1, 2011 - smart meters questioned by some

Smart meters are being rolled out by utilities across the country.  Regulators including FERC and state PUCs have approved their installation based on perceived benefits such as improved customer service, enhanced storm restoration efforts, and reduced costs for both ratepayers and utilities.  Yet a number of challenges have been lodged against smart meter programs.  For example, after ratepayer complaints and requests for investigation, the Maine PUC has opened an investigation into one utility's implementation of smart metering.  Concerns include privacy, alleged harmful effects of electromagnetic radiation, and the loss of meter-reading jobs.

The New York Times recently ran an interesting look at some of the opposition in California and Maine, noting that some Tea Party activists are joining the fray, as well as others concerned about health effects despite several studies concluding that smart meters pose no threat to human health.

What will end up happening with smart meter programs?  Will proponents' arguments outweigh the opposition's concerns?

January 7, 2011 - data center power demands

As the volume of digital data we create and consume increases, how much electricity is required to store, manage and analyze this information?  Smart grid technology has been described as relying on the "internet of things", a vision becoming real of constant real-time data communications between interconnected devices like home appliances, heating systems, and vehicles and the overall power grid.  This will represent a multifold increase in the volume of data being produced - and for those entities interested in analyzing that data, a likely increase in the volume of energy required to do so.

Even now, when smart grid communications are still a relatively small portion of the total volume of data flying around the country, it can take a surprisingly large amount of electricity to run a data storage and analysis center.  In Utah, the National Security Agency has just broken ground for its Utah Data Center, a complex enclosing about 1 million square feet of space, 100,000 square feet of which will be devoted to computer hardware.  Sen. Orrin Hatch has been quoted as describing the data center as creating 100 to 200 jobs for information technology specialists and engineers.  The NSA describes the data center as a component of the Comprehensive National Cyber-security Initiative designed to help the intelligence community meet domestic cyber-security requirements.

So how much power will the Utah Data Center consume?  Apparently up to 65 megawatts.  Indeed, the availability and cost of that much power was one factor behind the siting of the facility in Utah.  In 2006, the agency reportedly nearly consumed the entire free electric capacity of the Baltimore, Maryland power grid, causing the agency to look elsewhere for the installation of this new computing capacity.  The relatively low cost of energy in Utah may also have been attractive; the EIA reports that the September 2010 average all-sector electricity price in Utah was just 7.42 cents per kWh, significantly below the U.S. average of 10.24 cents per kWh for that time period, let alone costlier markets like Washington, D.C. (13.74 cents/kWh), California (15.27 cents/kWh), or Connecticut (17.26 cents/kWh).

As society generates more and more data, can we expect to see more and more data centers?  Will they consume more and more electricity?  Because data can be directed to any geographic location, does this place areas with less expensive power at a relative advantage for the economic development opportunities posed by data centers?

January 5, 2011 - Maine PUC opens smart meter investigation

Smart grid infrastructure has the potential to not only reduce the cost of electricity to consumers, but also to enable society to use energy more wisely.  Smart meter installation programs have been approved by FERC, and are moving forward in a number of utilities' service territories.  In Maine, Central Maine Power's $192 million Automated Metering Infrastructure (AMI) program was originally approved by the Maine Public Utilities Commission in February 2010 (Docket Number 2007-215).  The PUC approved the AMI program based on its benefits, including improving customer service, enhancing storm restoration efforts, and reducing both ratepayer and utility costs.  CMP secured a federal Department of Energy (DOE) grant to fund about half the cost of the AMI program.  Smart meters are now being installed in homes and businesses in CMP's territory, with over 50,000 already deployed in the field out of about 620,000 total meters to be installed.

Yet when it comes to the details of the rollout, concerns have been raised including the alleged lack of an opt-out for ratepayers who do not wish to be metered through smart meters.  Two separate ten-person complaints were filed to the PUC requesting an investigation of the AMI program (Docket Numbers 2010-345, and 2010-389).  This week, the Maine PUC voted unanimously to open an investigation of the issues raised, including both whether there truly is no opt-out, as well as whether such a lack of an opt-out would be “unreasonable, insufficient or unjustly discriminatory”.  The investigation may also include an evaluation of the availability and technical feasibility of alternative metering technologies that don't rely on wireless communications, as well as the cost implications of any such alternatives.

The formal order opening investigation should be issued shortly, with opportunities for public comment and participation.  Will the PUC find that the smart metering program is being implemented properly?  If smart metering brings public benefits to ratepayers, what should utilities do to educate the public about these benefits?

July 28, 2010 - Alta Wind Energy Center breaks ground; PACE financing

Today's picture: Central Maine Power transmission lines off Route 201 in Topsham, Maine.

In California, the Alta Wind Energy Center — with plans for thousands of acres of turbines to generate electricity for 600,000 Southern California homes — officially broke ground yesterday.  Here's the official project website, which is running a bit slowly today (likely due to all the interest in the project).  Terra-Gen Power, LLC does have a slick website that is worth checking out.  Some highlights include:

• The Alta Wind Energy Center (AWEC), under developed by Terra-Gen Power, is composed of multiple projects.  The first AWEC development is the Alta-Oak Creek Mojave Project.
• The Alta-Oak Creek Mojave Project will be composed of up to 320 wind turbine generators and supporting infrastructure.
• The Project will be developed primarily on privately-owned land adjacent to existing wind energy developments in the Tehachapi area of California.
• The Project is projected to add 50 full-time jobs to the Kern County economy.

 Interest in smart grid deployment is growing.  Federal policy supports smart grid development, and many states are following suit with more specific provisions.  For example, this spring, the Maine Legislature enacted LD 1535 (now P.L. 2009 Ch. 539).  This bill, sponsored by Representative Jon Hinck of Portland, gives Maine a specific smart-grid policy for the first time.  Both CMP and Bangor Hydro, Maine's largest investor-owned utilities are already rolling out smart meters; the legislative policy declaration builds upon this head start.

In enacting the smart grid bill, the Maine Legislature found that:

• The cost of electricity to consumers in this State is high in comparison to costs in similar markets and impedes economic development;
• The State has recognized the consequences of climate change and has committed to policies to reduce emissions of greenhouse gases;
• The State's electric grid and long-term infrastructure investment are vital to continued security and economic development, and smart grid functions will deliver electricity from suppliers to consumers using modern technology to increase reliability and reduce costs in a way that saves energy and to enable greater consumer choice;
• The State currently lacks a comprehensive smart grid policy but faces critical decisions regarding the implementation of smart grid functions and associated infrastructure, technology and applications, and the commission and the Legislature will play central roles in making those decisions; and
• It is vital that a smart grid policy be developed in order to ensure that all ratepayers and the State as a whole are afforded the benefits of smart grid functions and associated infrastructure, technology and applications.

Based on these findings, the Legislature enacted a policy of promoting the development, implementation, availability and use of smart grid functions and associated infrastructure, technology and applications in the State.

With this policy in place, the ball is now in the court of smart grid infrastructure developers.  We now have a law that will support roll-out of smart grid projects in Maine.  Who will be the first to propose one?

A bit of personal news, related to energy: an article I co-authored with a colleague and a client has been published in Paper360 Magazine. Click through to read about how a pulp and paper mill navigates the waters of compliance with the Regional Greenhouse Gas Initiative (RGGI) and other climate change regulation.



How about PACE financing? PACE-promoting provisions got stripped out of the current Senate energy bill. These tweaks are viewed as necessary to let PACE programs flourish, as government-backed lenders Fannie Mae and Freddie Mac have suggested that they won't play with PACE.

July 22, 2010 - Senate energy bill uncertain; FERC moves forward with smart grid standards; Maine dam removal

The U.S. Senate's summer session is almost over, and we don't have an energy bill yet. With just 13 business days left before a month-long recess, Senate Majority Leader Harry Reid is reported to be considering an energy bill that doesn't address emissions from electric utilities. (Utility issues may be split off into a separate bill to be introduced this week -- though time is short and consensus is lacking.) Critics of this proposal worry that the utility issues are the most important, and thus should not be glossed over. Still, passing something could help improve energy markets, and could certainly show Congressional confidence in, for example, renewable energy (or, for that matter, in coal).

The Federal Energy Regulatory Commission recently received a staff update on the process of selecting smart grid standards (PDF). Laws including the Energy Independence and Security Act of 2007 have given FERC the duty of developing and adopting interoperability standards and protocols necessary to ensure smart-grid functionality and interoperability with the nation's electric grids.

In plain language, FERC wants to ensure that your utility's infrastructure can have two-way communication both upstream (with the regional grid) and downstream (with your home/business/appliances). Ultimately smart grid adoption may overturn even this "upstream/downstream" paradigm, as end-use consumers take on more characteristics of distributed generation or demand response.

To that end, FERC's staff has been working with the National Institute of Standards and Technology to develop proposed standards. FERC anticipates a proceeding to review the standards later this summer.

Do you want to play in the smart grid market? Have a technology that you want to make sure is interoperable with what the other players are developing? Now is your chance to weigh in. Keep an eye on FERC Docket No. AD10-15-000...




The Maine Department of Environmental Protection has approved the final round of state permits required for a major Penobscot River dam removal project. A coalition led by the Penobscot River Restoration Trust will now implement the $50 million project. Three dams will be removed -- Howland, Veazie, and Great Works -- restoring access for sea-run fish to almost 1,000 river miles. All FERC and state approvals have been secured; the next step is finalizing U.S. Army Corps of Engineers permits, which are expected to be issued later this summer. Interestingly, fish passage at Howland was not universally supported, due to concerns that invasive northern pike could swim upstream and destroy Maine's blue-ribbon brook trout and salmon fisheries upstream.

4/9/10: an in-depth look at the rate impacts of Ontario's feed-in tariff and green energy policies

Today I'm taking a more in-depth look north of the border at what one Canadian province is doing to encourage green electricity generation -- and at the electric rate impacts of this policy.

As you may know, Ontario plans to eliminate its coal-fired power plants by 2014 and replace them with cleaner energy sources. In October, Ontario unveiled the Green Energy Act, which includes a set of feed-in tariffs that guarantee renewable generators fixed, above-market prices for 20 years to feed their production into the electricity grid. Yesterday, the province has announced 184 contracts for green energy projects, totalling 2,500 MW.

Minister of energy and infrastructure Brad Duguid said these contracts will generate 20,000 direct and indirect "green jobs" and attract $9 billion in private investment. In addition, Ontario is seeing interest in local siting of manufacturing facilities to produce the products and components needed to site renewable generation. In the last three months, Ontario has received commitments from both South Korea’s Samsung C&T Corp. and Germany’s Bosch Solar Energy to site manufacturing facilities in the province. It is assumed that the feed-in tariffs and contracts are required to incentivize this economic development activity.


But at what cost? The Globe and Mail has a good article detailing how Ontario is poised to face the highest electricity prices in Canada, replacing PEI as the province with the most costly power. Projections show that residential customers in Ontario were already facing a 25% rate hike, paying $300 more a year on average for electricity by the end of 2011. The green energy contracts will add another 5%, or $60 a year by 2012. Consumers' total cost, including distribution, may rise to 14.54 cents in 2011, while the average residential rate in the United States will rise just 2 per cent to 11.74 cents next year.

Simultaneously, a "smart grid"-related initiative will raise most residential rates even further. Ontario is introducing time-of-use billing, charging 9.3 cents per kWH during peak periods and 4.4 cents during off-peak periods. One forecast suggests this will result in a $50 a year increase for the average residential ratepayer. Of course, those ratepayers who can successfully shift their load to off-peak hours -- whether through careful management, or investment in appliances and technology systems that do the management for them -- might be able to reduce their costs through this move.

On top of all this, the province -- like many U.S. states -- is exploring tax hikes and broadening of the tax base to raise funds. In Ontario, a new harmonized sales tax will add 8 per cent to everyone’s bill starting July 1, or $98 a year for the average bill.

It will be interesting to watch as Ontario policymakers pursue these initiatives. Will there be ratepayer backlash? Or will ratepayers take the rate increases in stride, and feel like they're getting something -- freedom from coal-fueled power plants and their environmental impacts -- for their money? Time will tell.

4/6/10

With the tragic explosion and collapse of the Upper Big Branch Mine in West Virginia, operator Massey Energy's stock is tumbling. Coal mining has always been dangerous. Will the Big Branch disaster influence policymakers away from coal as a fuel source for electric generation? At least some financiers believe not, at least not enough to deviate from their "buy" rating. It will be interesting to see how the big coal lobby responds to the certain calls for greater government oversight of mine safety regulations.

Google and 46 other companies have asked the President for better real-time information on electricity usage. The group, including AT&T, Comcast, Hewlett-Packard, Verizon and Best Buy, wants better executive-branch support for technologies and devices that will help consumers measure their energy use in real time, and thereby to make better decisions -- the Prius effect. Beyond the social good that this would empower, no doubt Google wants to sell you the technology and interfaces to make this happen.

Premier Power Renewable Energy, Inc. has signed a Memorandum of Understanding with REgeneration Finance, LLC to fund solar PV projects ranging in size from 250kW to 2MW, in California, North Carolina, New Jersey, and Pennsylvania.

In offshore ocean energy news, a University of Delaware study concludes that it has figured out how to link offshore wind arrays to avoid the need for onshore backup power.

Maryland is pushing for a more rapid ramp-up of its solar RPS. Maryland law now requires utilities to source 2 percent of their power from solar sources by 2022, but there is a proposal afoot to accelerate deployment and increase penalties. 15-year projections suggest residential consumers might pay $2 more per month, beyond the current average monthly bill of $150 -- which some say will add to $1 billion over 15 years. Interestingly, there isn't enough solar PV in Maryland today: utility companies paid $1.2 million in penalties in 2008, and if penalties increase further, that number will rise. If the policy objective is to increase renewable deployment, you have to wonder if increasing penalties is the most effective way to get there.

Virginia Governor Bob McDonnell has signed several green energy bills passed by the General Assembly this session. Key features include: a $500 tax credit to employers per green job created; increased funding and organizational support for clean energy research; the creation of the Virginia Offshore Wind Development Authority; and bonuses for investor-owned electric utilities who use wind energy.

Bangor Hydro is proceeding with an $8 million investment in smart grid infrastructure, despite not winning federal stimulus funding to support the project. Bangor Hydro plans to build on the company’s existing "advanced metering infrastructure". The utility projects this may add 50 cents to the typical residential bill.

Meanwhile, CMP's $190 million plan to install a new automated meter system at homes and businesses -- which did win $96 million in stimulus funding -- is drawing opposition from members of the International Brotherhood of Electrical Workers Local 1837. The union laborers are concerned that the automated meters will lead to 141 layoffs, including 85 meter readers. The Maine Public Utilities Commission is holding a public hearing today in Hallowell on the plan. CMP anticipates installing the meters in 2010 and 2011.

In Canadian news, through government utility Nalcor, Newfoundland and Labrador are commencing legal action against Hydro-Quebec over the Upper Churchill power sales agreements. Under the existing long-term contract, HQ pays one quarter of one-cent per kWh, and one-fifth of one cent for the 25 years starting in 2016 -- less than 5 per cent of the power's commercial value. According to Newfoundland and Labrador Premier Danny Williams, in 2008, Hydro-Québec reaped profits of about $1.7 billion from the Upper Churchill hydro dams, while owner Newfoundland and Labrador was paid $63 million. Nalcor will also ask Quebec's Régie de l'Énergie to require HQ to provide access to its transmission system for export of power from the proposed Lower Churchill expansion project.

Also in Canadian news, there's been an odd wrinkle in the HQ acquisition of NB Power. A leaked document suggests that New Brunswick's power transmission and distribution systems are no longer for sale; NB Power would continue to operate as a New Brunswick-owned and operated Crown corporation. The revised deal is reportedly now worth $3.2 billion and would still include hydroelectric facilities and the Point Lepreau nuclear power plant near Saint John, N.B. Under the revision, the 5 year rate freeze for residentials would remain in place, but industrials face a smaller rate reduction. The revised deal was reached by the provincial Liberal government after significant criticism that it, like the Upper Churchill contract, gave too much power to Quebec.

12/17/09: FERC news and more

A few tidbits from FERC:

Implementing its new smart grid policy for the first time, the Commission approved PG&E's recovery a portion of its costs in transmission rates for a regional project that will ensure electric power reliability for consumers and integrate variable renewable resources into its system.

In LNG news, FERC approved the 1 Bcf/day Jordan Cove LNG facility to be located in the North Spit of Coos Bay in Coos County, Oregon. The Commission also reaffirmed its approval of the AES Sparrows Point facility in Maryland, despite late-filing interveners' attempt to require a supplemental environmental impact statement. Notably, the votes on both docket items were 3-1 in favor, with Chairman Wellinghoff dissenting.

FERC continues to refine its enforcement procedures. The Commission released its 2009 Report on Enforcement (42 page PDF), noting that its 2010 enforcement priorities include fraud, market manipulation, and reliability. FERC also improved transparency in enforcement, by authorizing the Secretary of the Commission to issue a “Staff’s Preliminary Notice of Violations” after the subject of an investigation has had an opportunity to respond to staff’s preliminary findings letter. The Commission hopes this will provide feedback to both the regulated community and the public on what kinds of things the Commission is investigating.

Vice President Biden continues to take the lead on energy policy matters. He is promoting a $5 billion increase in tax breaks established last February for clean energy manufacturing. The program would award a 30% tax credit to new or expanded factories that make products such as wind turbines, solar panels, and electric vehicles. Will Congress go for this?