State Regulators: Driven By Reliability

Can natural gas supply keep up with demand for power?
Fortnightly Magazine - November 2004


Can natural gas supply keep up with demand for power?


Things are looking up for the energy industry, but tough issues remain. Regulators-forced to grapple with the mismatch between volatile natural-gas prices and years of building gas-fired power plants-have learned a thing or two. They now insist on new rate schemes and risk-management methods while promoting the use of liquefied natural gas.

And while the August 2003 blackout has faded a bit from memory, reliability and utility infrastructure development remain at the top of the list of important issues. Competition also may be resurging, as California again ponders the benefits of retail choice-this time based on a core/noncore market structure.

This year's Regulators Forum spans the different regions of the country, touching all these issues.

Arizona: Southwestern Reasoning

Questioning FERC

"Arizona utilities have not sought, and the commission has not granted, pre-approval of cost recovery for participation in infrastructure projects. The unique and extraordinary circumstances in Arizona's natural-gas infrastructure support the commission's consideration of pre-approved costs."

Marc Spitzer, Chairman, Arizona Corporation Commission

Q: What is Arizona doing to deal with volatility and increases in natural gas prices, as well as predictions of lack of gas supplies?

A: Two common ways of addressing possible concerns with gas supply reliability and flexibility are the development of natural-gas storage, particularly market area natural-gas storage, and the ability of natural gas-fired electric generation to have a backup fuel source.

The development of natural-gas storage has in recent years been widely recognized as important in enhancing the natural gas infrastructure in Arizona. The existing natural-gas storage on the eastern end of the El Paso system, such as Washington Ranch, provide system benefits, but it takes several days for natural gas to travel from west Texas to Arizona, so production area storage does not provide the same ability to quickly respond to rapidly changing local conditions. It is unclear at this time if or when natural-gas storage facilities will be constructed in Arizona. Additionally, liquefied natural gas (LNG) imports are increasingly being looked at as a substantial source of natural gas supplies in the future, though siting issues remain for LNG facilities.

In a substantial change of course, on Dec. 18, 2003, the Arizona commission proposed a "Policy Statement Regarding New Natural Gas Pipeline and Storage Costs." In this document, the commission made specific policy statements about supply/infrastructure diversity, supply/infrastructure planning, the commission's approach to new infrastructure projects, individual utility circumstances, and reporting.

In two recent decisions, the commission approved applications by Southwest Gas Corp. and Arizona Public Service for pre-approval of certain costs if those entities participate in the Silver Canyon Project, subject to a number of conditions. The Silver Canyon project is a proposed new pipeline which Kinder Morgan Energy Partners would build from the San Juan supply basin in northwest New Mexico to Phoenix and then to the California border. The pipeline would provide additional direct access to San Juan gas as well as indirect access to gas in the central Rockies area. Traditionally, natural-gas prices in the San Juan supply basin have been lower than prices in the Permian supply basin.

Traditionally, Arizona utilities have not sought, and the commission has not granted, pre-approval of cost recovery for participation in infrastructure projects. While the commission supports the traditional method as standard operating procedure, the unique and extraordinary circumstances present in Arizona's natural-gas infrastructure support the commission's consideration of pre-approved costs.

Q: What is next on the regional transmission organization (RTO) agenda in Arizona?

A: The commission and Arizona utilities have been and remain very active in shaping the direction of the WestConnect RTO. They, along with the other members, continue to evaluate changes and solutions on a cost-benefit analysis. Additionally, there has been significant discussion of seams issues among the three Western RTOs as well as the Western Interconnection.

WestConnect is still proceeding on a phased implementation basis. In the spring of 2004, the first step of implementation occurred where WestConnect supported and participated in WesTrans in an effort to bring about an OASIS system across the multiple participants' systems, including some outside of WestConnect's footprint, to create a transparent transmission reservation system in the West.

Next on WestConnect's agenda is its consideration of the proposal of how to make Transmission Transfer Capacity (TTC) calculations transparent. This has historically been done by the owner of each transmission line. Addressing this in an open forum should be helpful and would support the WesTrans common OASIS system.

Q: Does Arizona have enough gas and electric infrastructure to ensure service reliability, and are adequate incentives in place to encourage building new facilities?

A: The fire at the Westwing substation has highlighted the need to locate a power plant within or near a load pocket, as that bolsters reliability of the entire power grid. If there is an outage at a key power plant or transmission line, power from the strategically located plant fills the gap and keeps the entire power grid stable.

The reliability of Arizona's access to natural gas is the largest threat facing Arizona, as virtually all of Arizona's natural-gas supplies have been provided through the El Paso Natural Gas pipeline system. Natural gas supply is now critically low, and Arizona has no production, zero storage, and constrained and costly pipeline transport. Additionally, it is unclear at this time if or when a number of LNG and storage projects will be completed, further exacerbating the lack of supply and attendant price increases. Clearly, one of Arizona's most pressing needs is to diversify its fuel supply.

Q: What is the future of retail competition in Arizona for gas and electric consumers?

A: Arizona has effectively no retail-level electric competition. However, with the filing of the APS rate case, the issues of competitive transition charges, stranded costs, and shopping credits will be re-evaluated. Whether or not retail electric competition ever develops-I know that it cannot arise without a stable wholesale electric market. Arizona has done what it can in that regard. It is now up to FERC. Ultimately, however, I believe that a partnership will develop between the states and FERC that appropriately balances commercial practices of the market with the reliability expectations of consumers.

In 2003, the Arizona commission approved the start of a competitive wholesale power solicitation. In what is known as the Track A Order, the commission's order on the first group of issues related to electric competition, APS and Tucson Electric Power (TEP) were required to procure, through a competitive solicitation process, power to serve their customers that cannot be produced from their existing assets. The Track B Process is designed to lay a framework for the competitive wholesale market by setting parameters and procedures for wholesale energy procurement. The process also ensures for the first time that the environmental impacts of generation will be measured and evaluated. Arizona will become a national leader in balancing the environmental impacts of electricity generation against economic costs.

Arizona has had retail competition in the natural gas market for over 10 years. However, the only customers taking advantage of such competition are large users of the commodity. Due to Arizona's climate, it does not appear likely that the average small business or residential customer would experience the same benefits as a gas customer in the Midwest or East Coast.

Q: Does Arizona have in place a quota for renewable energy? If not, do you expect to implement one?

A: In February 2001, the commission voted to codify the Environmental Portfolio Standard (EPS) as a formal rule.

The EPS requires regulated utilities to generate a minimum percentage of their total retail energy sales from renewable sources, beginning in 2001. The percentage increases each year to 1 percent in 2005 and tops out at 1.1 percent in 2007. The decision applies to companies regulated by the commission that sell retail electricity in Arizona. The EPS covers solar technologies such as solar generation, solar water heating, and solar air conditioning. Non-solar technologies such as landfill gas generators, wind generators, and biomass generators are also qualifying technologies.

Beginning in 2001, Arizona ratepayers started paying a small portion of the costs associated with the increased investment in environmentally friendly technologies. I am quite familiar with pollution's "external cost." The benefits of cleaner air on human health and welfare argue in favor of the higher cost of renewable energy

Q: What is the issue of greatest importance to Arizona?

A: The commission exists, among other things, to ensure Arizonans receive "adequate, economical and reliable electric power." This mandate is the issue of greatest importance to the commission.

The balancing of competing interests, especially among rates, reliability, and rate of return on various issues are issues I believe the commission has successfully addressed, although at times amid great toil and debate. Our plate is full of issues such as natural-gas price volatility, the never-ending need for the siting of infrastructure in the face of NIMBYism, addressing the water industry's adherence to the new arsenic standard, enhancing telecommunications competition, and the pending leveraged buyout of an electric utility.

Arizona needs utility infrastructure, and Wall Street is the gateway to construction of needed capital projects.

Financial interests have been critical of congressional enactments and regulatory policies arguably harmful to capital investment. However, recent Wall Street history reveals some unsettling developments, suggesting the "invisible hand" is not properly functioning.

The proper functioning of financial markets requires rational financial actors. Corporate management is under a microscope after some noted implosions. The financial community quite rightly calls for rational federal and state policies with regard to the regulation of utilities. I can only hope that the community examines the rationality of its own actions and decisions.

California: Western Growth

More Power Needed

"Energy efficiency and demand response are key, but they cannot meet the full need, and California's economy will depend on our ability to build new power plants where they are needed."

Michael R. Peevey, President, California Public Utilities Commission

Q: What is California doing to deal with volatility and increases in natural-gas prices, as well as predictions of lack of gas supplies?

A: The California Public Utilities Commission (CPUC), along with the California Power Authority and the California Energy Commission, has adopted an Energy Action Plan (EAP) that, among other things, lays the groundwork for ensuring reliable supplies of natural gas for the state. The EAP discusses the need to identify critical new gas transmission, distribution, and storage facilities in order to meet California's future needs; monitor the gas market to identify any exercise of market power and manipulation; and work to improve Federal Energy Regulatory Commission (FERC)-established market rules to correct any observed abuses.

In addition, the EAP calls for the evaluation of the net benefits of increasing the state's natural-gas supply options, such as liquefied natural gas (LNG), and supporting the electric utilities and gas distribution companies entering into longer-term contracts as a hedge against volatile and high spot market prices. As a first step in this process, the commission is currently establishing policies and rules to ensure reliable, long-term supplies of natural gas to California. Phase One of this important process included looking at issues such as interstate pipeline capacity contracts, and LNG and interstate pipeline access. Implementation of the EAP is an important step for California's energy agencies to take together to help achieve the state's overall goal of adequate, reliable, and reasonably priced electrical power and natural gas supplies.

Q: What is next on the agenda for the California PUC?

A: On the energy side of the CPUC's work, we are reviewing the long-term procurement plans of the utilities to ensure reliable supply of electricity to California while taking into consideration goals for renewable energy and energy efficiency. In January 2004, the CPUC adopted an integrated procurement process for the utilities, which requires them to achieve a planning reserve margin of 15 to 17 percent by Jan. 1, 2008. The CPUC is now looking at accelerating that deadline to 2006. The CPUC is also developing "resource adequacy" standards for proving that power is deliverable where and when it's needed. To avoid over-reliance on spot purchases, the CPUC requires utilities to show in advance that they have at least 95 percent of their needs locked up and under contract. All of these activities should lead to the development of additional infrastructure in California, both on the supply side-including additional renewable and conventional generation, as well as transmission-and the demand side, including energy efficiency and demand response. As part of ensuring reliable supplies of natural gas for the state, the CPUC is challenging the ruling of FERC, which stated that FERC has sole jurisdiction over the safety and siting of LNG facilities in California.

Q: Does California have enough gas and electric infrastructure to ensure service reliability, and are adequate incentives in place to encourage building new facilities?

A: New power plants must be built in California. Energy efficiency and demand response are key, but they cannot meet the full need, and California's economy will depend on our ability to build new power plants where they are needed. The CPUC's pending procurement implementation order will give the utilities the authority and guidance they need to solicit third-party power plant proposals and also to propose more traditional utility-owned power plants themselves. We are also developing a new power plant bidding process that will be open and transparent.

In May 2004, we approved contracts for two new large power plants near San Diego-Palomar, which will come online in 2006, and Otay Mesa-totaling over 1,000 MW of capacity. Additionally, as part of our commitment to a diversified resource mix, at the same time the commission approved a 45-MW plant designed to meet peak loads, a 45-MW renewable project and up to 30-MW of demand response. In December 2003, the CPUC approved Southern California Edison's 1,054-MW Mountainview Project, which will come online in 2006. In addition, several new plants, such as the Metcalf facility in San Jose, will be in operation by 2006.

Further, to meet the near-term energy needs of California, the commission is working closely with the independent system operator and the investor-owned utilities to ensure that existing power plants are kept operational until they can be replaced with newer, cleaner, and more efficient plants.

Finally, transmission has to be available to get the power to the consumer. The CPUC has approved three new transmission projects this summer. The Pacific Gas and Electric Co. (PG&E) Jefferson-Martin 230-kV line will beef up capacity in San Francisco and the Peninsula by 2007; the Mission-Miguel 230-kV line will give San Diego customers access to new generation near the California/Mexico border and in western Arizona, along with relieving congestion in the San Diego Gas and Electric Co. territory; and the Viejo System Project will improve local reliability in the Mission Viejo area of Southern California Edison's territory. These projects join the more than 10,000 MW in transmission system expansions approved by the CPUC since 2001.

Q: What is the future of retail competition in California for gas and electric consumers?

A: One approach that the CPUC has been examining is the idea of a Core/Noncore retail market structure that would balance the desire of electric utility customers for choice in service offerings and providers with the needs of the utilities and California for planning certainty and the timely recovery of costs for generation resources already committed to those customers. I support this concept because of the value all energy customers could gain by increasing their control over costs and terms of delivery and the impact that the presence of competing suppliers would have in terms of causing the investor-owned utilities to become more efficient in acquiring and delivering energy supplies, which would benefit both core and noncore customers. In addition, there are many benefits beyond cost savings to customers when competition in the retail market is increased, such as innovation and basic improvements in customer service. Core customers would also benefit from choices such as time-of-use rates, real-time pricing, and renewable pricing options.

Q: Does California have in place a quota for renewable energy, and how is it working, or if not, do you expect to implement one?

A: In 2002, the Renewable Portfolio Standard-S.B. 1078-became law. This requires an annual increase in renewable generation of 20 percent by 2017. The CPUC is aggressively implementing this policy and has accelerated the completion date to 2010. In addition, a new bill awaiting signature by the Governor-S.B. 1478-would ratify our acceleration of the deadline. () The EAP commits the CPUC to looking first at renewable sources for the state's power. Since August of 2002, the CPUC has authorized over 700 MW of utility procurement contracts from renewable resources, such as biomass, geothermal, wind, and small hydro. To get to a 20 percent renewable share in utility resource plans by 2010, the CPUC has set annual milestones and established an open and transparent competitive process for the utilities to solicit renewable power. PG&E and SDG&E have active solicitations under way today, and some of the capacity chosen in that process may be available as early as next year.

Q: What is the issue of greatest importance to California?

A: In addition to ensuring adequate, reliable, and reasonably priced electricity and natural gas, the issue of whether to re-open California's energy market to competition is of great importance to consumers in California. I also believe it is extremely important to keep the focus on reducing the contribution of electricity and gas production and use in California to greenhouse gas emissions, and therefore reduce the impacts of global climate change. Finally, I support a continuing focus on integration of the energy policy of California among its myriad energy-related agencies and commissions, to ensure efficient and effective regulation and policy.

Kentucky: Southern Straightforwardness

Holding the Line

"Preservation of Kentucky's low-cost electricity is the state's highest priority."

Mark David Goss, Chairman, Kentucky Public Service Commission

Q: What is Kentucky doing to deal with volatility and increases in natural gas prices, as well as predictions of lack of gas supplies?

A: Because states have no control over the wholesale price of natural gas, the Kentucky PSC has focused its efforts on public outreach to prepare consumers for higher home heating costs. Outreach efforts have included briefings for the news media, media events, news releases, presentations to community groups, and radio public service announcements. The education effort has emphasized energy conservation measures such as weatherization and enrollment in even-payment plans as a means of bringing predictability to utility bills.

The PSC has encouraged local distribution companies (LDCs) to consider both physical and financial hedging programs as a means of ensuring adequate supply and reducing price volatility. LDCs engaging in hedging are required to submit their programs for PSC approval. The PSC also has monitored summer storage activity by LDCs.

Q: What is next on the RTO agenda in Kentucky?

A: The Kentucky PSC has consistently supported the creation of regional entities to improve the reliability, stability, and flexibility of the transmission system. However, if regional transmission facilities are improved in order to facilitate the long-distance transport of electricity, the costs of the improvement should be borne by the beneficiaries of the services, i.e., the cost-causers, and not by the native-load ratepayers. In addition, membership in an [RTO] should not be detrimental to Kentucky consumers, either with respect to preserving the priority of native loads-as required by Kentucky statute-or with respect to maintaining Kentucky's low electric rates.

With respect to specific RTO matters, there is a case pending before the Kentucky PSC investigating whether or not Louisville Gas and Electric (LG&E) and Kentucky Utilities (KU) should remain a member of the Midwest Independent System Operator (MISO). We will also be monitoring the integration of AEP into PJM Interconnection Inc. (PJM).

Q: Does Kentucky have enough gas and electric infrastructure to ensure service reliability, and are adequate incentives in place to encourage building new facilities?

A: In Administrative Case 387, the Kentucky PSC concluded that there is sufficient infrastructure to ensure electric service reliability in the near future for native load within Kentucky. However, the same investigation noted the presence of potential bottlenecks should there be substantial growth in wholesale transactions that would increase north-south interstate flow through transmission infrastructure in Kentucky. There are concerns that the infrastructure would need upgrades to facilitate such wholesale transactions.

In the wake of the August 2003 blackout, the PSC initiated another review of the electric transmission infrastructure, focused on system stability and reliability. This review is due to be completed this fall.

Because of the ability of jurisdictional utilities to recover costs through rates, adequate incentives are in place to maintain sufficient infrastructure to meet the needs of ratepayers. Jurisdictional utilities are required to conduct long-range planning through Integrated Resource Plans that are submitted for PSC review.

Gas infrastructure generally appears to be sufficient at this time. There are some concerns regarding the capacity of gathering lines in portions of eastern Kentucky that are undergoing significant new exploration and production activity.

In the interim, our focus is on ensuring system reliability and promoting an efficient market.

Q: What is the future of retail competition in Kentucky for gas and electric consumers?

A: Kentucky enjoys the lowest electricity costs in the nation. These low costs, as well as a high degree of service reliability, have been achieved within the framework of a traditional model of vertically integrated, regulated utilities. Given this situation, there is little advantage to or impetus for retail competition in Kentucky. No legislation promoting retail competition has been introduced in recent years, and we are unaware of any moves to do so in the immediate future.

Kentucky has had in place since 2002 laws regulating the siting of merchant generation facilities. Three such facilities, all using coal as a primary fuel, have been approved since 2002, but none are currently under construction. There are five gas-fired merchant facilities in Kentucky, all built prior to the passage of the siting legislation. Four are operating; the fifth is in non-operational status.

Retail choice for natural gas consumers has been introduced on a trial basis by some utilities in Kentucky. However, these programs have drawn limited interest.

Q: Does Kentucky have in place a quota for renewable energy, and how is it working, or if not, do you expect to implement one?

A: Kentucky has no such quota, and does not expect to implement one. The PSC has encouraged and approved renewable energy projects built by jurisdictional utilities, notably a number of small-capacity generators fueled by methane collected from landfills.

Q: What is the issue of greatest importance to Kentucky?

A: Preservation of Kentucky's low-cost electricity is the state's highest priority. Low-cost electricity is a major element in Kentucky's economic development efforts, both as an incentive in attracting industry and as a factor in ensuring a low cost of living for residents. The Kentucky PSC wants to continue the state's success in providing low-cost electricity while maintaining safe and reliable electric service provided by financially healthy utilities.

Massachusetts: Bay State Thinking

Contemplating Price Volatility

"One issue that was highlighted during this past January was the region's dependency upon natural gas for electricity generation."

Paul G. Afonso, Chairman, Massachusetts Department of Telecommunications and Energy

Q: What is Massachusetts doing to deal with volatility and increases in natural gas prices, as well as predictions of lack of gas supplies?

A: To alleviate the volatility in natural gas prices that we have experienced in New England recently, the department established a policy whereby [LDCs] may use financial risk-management instruments as part of their natural-gas procurement protocol (). Customer participation in LDC hedging programs is voluntary, and the costs associated with such programs are recovered from only the customers who choose to participate in them. The department approves hedging proposals on a case-specific basis to ensure that such proposals do not negatively affect gas unbundling, customer choice, and retail competition in Massachusetts.

To date, the risk-management procurement policy is doing well. For example, the department recently approved a proposal by KeySpan Energy Delivery (KeySpan) wherein the company modified its gas procurement practices to mitigate price volatility for its customers (). Under this program, KeySpan will lock in the price for all of its domestic non-storage gas supplies (equally over the 12-month period). In total, this affects approximately one-third of KeySpan's projected normal winter requirements.

In 2001, in an effort to further deal with the volatility in gas prices, the department amended its regulations to allow gas companies to make interim filings for recovery of gas costs, when projected under- or over-collections exceed five percent of the total gas costs to be recovered in the period. The department has encouraged gas companies to request these adjustments.

In order to continue to protect customers from volatility in gas prices, the department has encouraged ratepayers to enroll in 12-month levelized billing plans.

Last, Massachusetts is progressive in developing cost-effective demand-side management programs. These energy-efficiency programs include energy audits, weatherization, and rebates for thermostats and energy-efficient appliances. All Massachusetts LDCs are required to offer such programs to all classes of ratepayers.

Q: What is next on the RTO agenda in Massachusetts?

A: On March 24, 2004, [FERC] approved, subject to conditions, the joint proposal of ISO New England (ISO-NE) and the New England transmission owners to establish an RTO for New England. Following settlement discussions with stakeholders to address issues that were not resolved by the FERC order, on Sept. 13, 2004, ISO-NE and New England transmission owners filed a settlement with the FERC that received broad support from NEPOOL members. This is a significant step forward in the formation of an RTO in New England, and although there are issues outstanding, I believe they can be resolved.

Specifically, resource adequacy and the completion of transmission projects in Northeast Massachusetts and Southwest Connecticut are current priorities. In June, the FERC issued an order addressing ISO-NE's locational installed capacity proposal, accepting some provisions and setting others for hearing. In late August, the ISO-NE filed testimony with FERC, which included revisions to its LICAP proposal. Hearings are scheduled to begin in February 2005.

In September 2004, the ISO-NE published its draft Regional Transmission Expansion Plan report for 2004, which identified transmission projects believed to be key to the reliability and efficiency of the New England system and Massachusetts in particular. As the blackout of 2003 pointed out, New England operates as part of an interconnected transmission grid. Resource planning within New England, coordinated on an inter-regional basis, is absolutely critical.

Q: Does Massachusetts have enough gas and electric infrastructure to ensure service reliability, and are adequate incentives in place to encourage building new facilities?

A: One issue that was highlighted during this past January was the region's dependency upon natural gas for electricity generation. Most of the new electric generation capacity added since 1990 is fueled by natural gas, and currently over 30 percent of New England's winter capacity consists of gas-only units. The January 2004 severe low temperatures, coupled with high electric and gas demands, was a stress-test for the bulk power system in New England-a test that was met successfully in that instance.

On the electric side, New England currently has adequate electric capacity in place. The question of adequate resources, however, is timely. Analysis of the markets is necessary to ensure that there is continued adequate generating capacity, and new rules may need to be established to ensure that new generation receives the appropriate signals for siting and market entry.

Q: What is the future of retail competition in Massachusetts for gas and electric consumers?

A: To date, the department has approved twelve suppliers and 10 retail agents to provide retail service in Massachusetts. Approximately 40 percent of the C&I customer load is acquired through competitive suppliers. This year, the department opened an investigation () wherein we will review the status of competition in the gas industry to determine if any modifications to the existing rules are needed in order to further enhance competition.

As for competition within the electric industry, the Department is operating under The Massachusetts Electric Industry Restructuring Act of 1997 wherein the legislature established a seven-year transition period during which distribution companies have been providing standard offer generation service to their "existing" customers (i.e., customers of record as of March 1, 1998) at below-market rates. This transition period ends on Feb. 28, 2005. Subsequently, standard offer customers who do not switch to a competitive supplier will be placed on default service, provided by distribution companies at market-based rates.

To date, approximately 50 percent of the large C&I customer load is acquired through competitive suppliers; the percentage of load acquired through competitive suppliers, for medium and small C&I customers, is approximately 20 and 10 percent, respectively. The department anticipates that, for larger customers, the elimination of below-market standard offer service, along with recent revisions to the department's default service procurement policies, will significantly increase the number of customers switching to competitive supply. Similar to the residential gas market, the residential electric market has been slow to develop.

Q: Does Massachusetts have in place a quota for renewable energy? If so, how is it working, or if not, do you expect to implement one?

A: By statute (), an [RPS] was established for all retail suppliers selling electricity to end-use customers in the Commonwealth. Pursuant to the law, there is a minimum percentage of new renewable resources that each retail electricity supplier must include in its resource portfolio. The minimum percentage ranged from one percent for calendar year 2003, and increases one-half percent each succeeding year until 2009 (at which point the minimum would be four percent) and by one percent per year thereafter until our sister state agency, the Division of Energy Resources, elects to suspend the annual increase. Retail suppliers can satisfy their RPS requirements by either purchasing the required number of renewable energy certificates through the New England Generation Information System or making alternate compliance payments to the Massachusetts Technology Council (which administers the state's Renewable Trust Fund) at an inflation-adjusted rate of $50/MWh.

Q: What is the issue of greatest importance in Massachusetts?

A: Massachusetts strives hard to ensure the public that facilities that provide us with electricity, gas, and water operate in a reliable, safe, and cost-effective manner. To that end, the department, at the request of the governor, reviewed events from the Aug. 14, 2003, blackout. The Massachusetts Task Force on Electric Reliability and Outage Preparedness concluded that several factors worked to protect the New England area from more extensive blackouts experienced elsewhere in the Northeast. First, automatic relays shut down the lines between New York and New England to protect individual transmission lines from damage; this effectively isolated New England. Second, the available electrical resources in New England following the blackout were sufficient to support the remaining load. Third, operators, utilities, and generators throughout New England worked together to stabilize the New England bulk power system. System operators had sufficient information to assess the situation and the authority to take action to stabilize the New England bulk power system, including disconnecting customers. The combination of a single, centralized control area, well-defined responsibilities, well-trained operators and a long history of coordination made it possible to stabilize, and then quickly restore, the New England bulk power system.

Massachusetts is exploring opportunities to create, through state and regional policy formulation and implementation, as well as system oversight, a more stable, more reliable electric system through investments in conservation, energy efficiency, and distributed generation. We are continuing with our policies that encourage the development of renewable resources in order to advance the goal of a diverse generation base.

Michigan: Great Lake State

Keeping Watch Over MISO

"MISO is currently the only RTO that has an established regional state committee (RSC)-the Organization of MISO States (OMS)."

J. Peter Lark, Chair, Michigan Public Service Commission

Q: What is Michigan doing to deal with volatility and increases in natural-gas prices, as well as predictions of lack of gas suppliers?

A: Michigan is a major natural gas consuming state, and thus has been significantly impacted by the current high price levels and unprecedented volatility in the national wholesale gas market. Despite a doubling in wholesale prices over the past three years, Michigan gas utilities' retail rates have consistently remained among the lowest in the nation. Low gas prices are attributed to a combination of aggressive use of utility-owned underground gas storage facilities and reliance on fixed-price supply contracts. The Michigan Public Service Commission (MPSC) has encouraged its regulated utilities to enter firm transportation agreements with interstate pipelines that allow direct access to major North American producing basins. Utilities then have the ability to purchase from different locations to obtain the lowest possible price. In addition, direct control of interstate gas transportation paths increases both short and long-term reliability by allowing Michigan utilities the flexibility to respond to regional production outages, declining production trends in mature producing areas, and new production developments.

Q: What is next on the RTO agenda in Michigan?

A: Most of the Michigan utilities are part of the Midwest ISO (MISO), an RTO headquartered in Carmel, Ind. The next major MISO event is the implementation of the coordinated wholesale (Day 2) market scheduled for March 1, 2005. The MSPC has been actively involved in the MISO stakeholder process and has participated in formal proceedings at FERC. MISO is currently the only RTO that has an established regional state committee (RSC)-the Organization of MISO States (OMS). The MPSC is an active member of the OMS, one commissioner serves as treasurer, another commissioner serves as chairman of an OMS work group, and several staff provides support for OMS activities.

MISO recently signed a joint operating agreement with PJM, an adjacent RTO serving the mid-Atlantic region, with the objective to create a joint and common market in the near future. American Electric Power (AEP), the utility that serves the southwest corner of the state, joined PJM on Oct. 1, 2004.

Q: Does Michigan have enough gas and electric infrastructure to ensure service reliability, and are adequate incentives in place to encourage building new facilities?

A: Ensuring that the electric and gas infrastructure is capable of providing reliable service to Michigan customers has been an MPSC priority for a number of years. The MPSC has initiated investigations and hearings to make certain that near-term electric generation capacity is adequate, even as traditional roles in planning, building, and maintenance of infrastructure have changed with the advent of competitive markets.

Federal and state initiatives have resulted in a 2,000-MW increase in transmission import capability into Michigan and a developing competitive energy supply sector emphasizing fuel source diversity. Michigan has added approximately 5,300 MW of utility and non-utility generating capacity since 1999. Regional system improvements and initiatives by MISO have also enhanced the reliability of the infrastructure.

The 2003 blackout brought to light the vulnerability of the transmission grid under the existing voluntary standards. The MPSC has joined many other organizations in supporting mandatory federal reliability standards that make FERC responsible for the reliability of the nation's electric highways.

Q: What is the future of retail competition in Michigan for gas and electric consumers?

A: State legislative amendments have been introduced and cases are currently before the MPSC that could have a major impact on the future of electric competition that began in 2000. Transition periods, recovery of emission abatement equipment costs, transition costs, return to service rules, cost-of-service rates, and other rate-design changes are being addressed.

Michigan's restructuring legislation does not require divestiture of electric generation or gas production assets as in other states, though both major electric utilities (Detroit Edison and Consumers Energy) have voluntarily divested their transmission assets. Customers may purchase their energy commodity needs from incumbent utilities under regulated rates or from alternative suppliers at rates set in the competitive market. In both markets, incumbent utilities retain regulated ownership, operation, and maintenance of the distribution system. This mixture of regulated and deregulated elements in the electric market has presented an ongoing challenge to balance the economic health of incumbent utilities and promotion of competition.

Q: Does Michigan have in place a quota for renewable energy and how is it working, or if not, do you expect to implement one?

A: Michigan does not have a quota in place for renewable energy. [RPS] legislation has been introduced at the state level, but there is no indication that it will be passed. Under the Michigan Renewable Energy Program, an unfunded mandate under electric restructuring legislation, MPSC staff is working with a broad-based collaborative to explore renewable energy policy options, including net metering. A report is due to the MPSC Nov. 30, 2004, in which staff will provide a review of initiatives, including renewable portfolio legislation in other states, and a proposal for how it might be implemented in Michigan.

Q: What is the issue of greatest importance in Michigan?

A: Service reliability is the number one issue facing the Michigan energy industry today. When Michiganians flip the switch they expect the lights to come on. The Aug. 14, 2003, blackout was a vivid reminder of just how highly interconnected and vulnerable the nation's electric grid has become.

Action on the part of state utility commissions, regional transmission organizations, and Congress are required to close the loop on national reliability matters, and provide greater assurance that another blackout will not occur. The MPSC has inquired into utility vegetation management procedures, ordered reporting on how generation and transmission load requirements will be met, and implemented stricter service quality and reliability standards. MISO has improved its monitoring and communication capabilities to address deficiencies raised in blackout investigations. Congress should now act to pass mandatory reliability standards with penalties for noncompliance and place the responsibility of grid stability on FERC.

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"Arizona utilities have not sought, and the commission has not granted, pre-approval of cost recovery for participation in infrastructure projects. The unique and extraordinary circumstances in Arizona's natural-gas infrastructure support the commission's consideration of pre-approved costs."
"Energy efficiency and demand response are key, but they cannot meet the full need, and California's economy will depend on our ability to build new power plants where they are needed."
"Preservation of Kentucky's low-cost electricity is the state's highest priority."
"One issue that was highlighted during this past January was the region's dependency upon natural gas for electricity generation."
"MISO is currently the only RTO that has an established regional state committee (RSC)-the Organization of MISO States (OMS)."