In policy revisions issued this Spring, the Federal Energy Regulatory Commission (Ferc or Commission) emphasised its strong commitment to customer-based, competitive wholesale power markets. Yet, the Ferc underscored an increasingly flexible approach to regional needs in outlining step-by-step refinements of its key market design proposal in response to Western and Southeast regional pressures, and escalating Congressional review. Regional hearings and technical conferences are being conducted by the Commission this month, while market design continues to be debated as part of US energy legislation to be finalised later this summer.

In its final rule, the Ferc will focus on the formation of regional transmission organizations (RTOs) and ensuring that all independent transmission companies (ITC's) use fair and effective wholesale market rules. Implementation schedules will vary depending on local needs and will allow for regional differences. But, all public utilities must join an RTO ? and functional implementation will be altered by relaxation of the scope and regional configuration requirements for an RTO. The Commission is signaling a shift back to an RTO-based platform while offering more flexibility on standard market design to reflect regional variations.

Background

The Commission had issued a standard market design proposal in July 2002 after over ten years of effort, countless rules, hearings and meetings that yielded deregulation in 15% of wholesale markets, and over 5% of retail markets by 2003. Since last year, the Commission continued its extensive outreach efforts with interested parties and announced reconsideration of several features of its proposal in addressing concerns raised by various stakeholders.

The policy revisions in the form of a White Paper respond to the numerous comments on Ferc's proposal and provide direction for the final rule expected after federal legislation is enacted later this year. It notes that a well-designed market will enhance wholesale competition and remove economic inefficiencies, stabilise supplies and price volatility, manage and mitigate market prices, and promote new infrastructure development.

The proposal advances the competitive markets envisioned by two earlier Commission orders ? Order Nos. 888 and 2000. Order No. 888, issued in 1996, opened up the nation's transmission grid through open access transmission tariffs. In 1999, the Commission issued Order No. 2000, which called for the voluntary creation of RTOs. RTOs promote increased efficiency through improved grid management and increased customer access to competitive power supplies through more independent grid management and pricing.

Revised Goals

The proposal, as reported by Ferc, is designed to establish a customer-based wholesale power market platform. In addition, the proposals in the White Paper envision a significant role for regional authorities in setting up regional power markets with increased reliance on RTO's. The Commission will rely on regional state committees to address significant market design features for their regions while ensuring that ?seams? issues between regions are minimised. This will operate to favor the status quo since states will be free to decide timetables, budgets and market monitoring.

In the White Paper, the Commission stated that:

? Practically all public utilities have voluntarily jointed RTOs or independent system operators, therefore all remaining utilities will be required to join, except for rural cooperatives only serving retail loads;

? Ferc jurisdiction over the transmission rate component of bundled retail sales is not needed to implement the plan; transmission jurisdiction will only arise over non-price terms and conditions for transmission used by wholesale customers to serve bundled retail customers;

? Provisions in the proposal regarding transmission planning and resource adequacy will be changed to clearly establish that state and local governments are decision-makers in these areas and Ferc's role is a supporting one, leaving these choices to the regional state committees;

? The Commission will emphasise the need for a transparent, well-monitored spot power market for last-minute imbalances between supply and demand (as well as other voluntary trades) and adopt a fair method of allocating costs of that service by RTO's or ISO's. A separate power exchange could not perform this function;

? The final rule will permit regional state committees to oversee the allocation of firm transmission rights (FTR's) to current customers based on existing uses of the grid. The Commission will not require that such rights be auctioned;

? The Commission will scrutinize mitigation proposals for their compatibility with RTOs within the same interconnection;

? The RTO or ISO will develop detailed market rules to be included in its Commission filing, including requirements that all bids must be physically feasible, certain reporting and cooperation obligations for investigations;

? The rule will give substantial weight to the regional state committees on the determination of the methodology used to allocate costs of existing and new transmission facilities;

? Certain core features (independent operation of the grid, establishment of regional state committees and development of a regional transmission plan) will be required at the onset of the proposal but RTOs, ISOs and their regional state committees may work out a timetable and budget for implementation of remaining elements (energy markets, congestion cost allocation and market monitoring);

? Utilities will not be required to divest their transmission assets into separate companies, but substantial incentives for divestiture will be considered ? as proposed;

? The Commission will allow flexibility on scope and configuration for RTOs and ISOs; and

? Network access service could serve as a baseline service offered by all RTOs and ISOs that use locational prices. RTOs and ISOs would be free to propose certain improvements or modifications to meet regional needs.

Independent governance standards for RTOs will be included in the final rule, but the Commission will decide governance issues and apply the standards on a case-by-case basis. The final rule will not override governance requirements already approved for an RTO. Nor will the Commission override decisions made without reservation in prior RTO orders.

A standard tariff provision limiting liability for transmission providers will be included in the final actions by the Commission. No liability would lie for ordinary negligence, and gross negligence will only yield liability for direct damages (not consequential or indirect damages).

For the purposes of the final rule, all of the characteristics and functions for RTOs would apply to ISOs, except for scope and regional configuration. And NERC standards on cyber-security will be adapted.

The Results for the Future

Transmission

? Load serving entities (LSEs) have risk exposure under the current Ferc announcement for securing transmission services and critical FTRs. Since these transmission rights will not be required to be auctioned, accessibility will be limited for new loads and load growth over a constrained system. Transmission constrained regions are likely to stay constrained. Once monopoly advantages are removed, utilities will likely file new tariff revisions seeking rate increases in transmission and distribution services.

? Interconnection policy has not been finalised with clarity, and is still under a cloud of utility-led opposition in several regions. Distributed generation and standard interconnection policy has been left open, and initially will be promulgated on a case-by-case basis.

? Transmission rate-making and funding of transmission improvements will become the next battleground. Through and out rates will appear more frequently as seams management issues proliferate in certain regions making it difficult to price merchant power to compete.

? With mixed signals for new transmission, new forms of transmission investment and regulation will be stimulated on a market basis under proposed ownership and regulatory incentives, especially if PUHCA is repealed under pending federal legislation.

? TVA, BPA and SEPA will seriously need to act and join regional grid activities to service, and secure market benefits, enhanced transmission revenues and more effectively compete. Otherwise, they become islands, new seams and further sources of congestion.

? Merchant transmission will struggle to secure financing; alternative forms of financing will be required working with existing market players to promote new transmission investment. Transmission will replace power marketing/ trading in driving the new post-SMD market for the remainder of the decade.

? Available transmission capacity (ATC) problems still exist for through traffic, and Ferc's effort to promote a secondary market in unused capacity (like natural gas) will now be left to political solutions in the regions, and not become a national policy objective.

? Human resource challenges will escalate as declining transmission human resources with experience will contend with a shortage of adequate physical transmission capacity. No amount of available FTRs will bridge these two gaps.

Generation

? Stranded assets for generation will be created in certain regions under these proposals and the confluence of other intra-corporate transfer and affiliate regulation cases. Affiliated power producers (APPs) could become a new super class of generation with their own private rate base supported by some state regulatory policies.

? No new market power breakthroughs have been provided; standards of conduct are still open and not resolved, instilling a lack of confidence in market-based outcomes.

? PURPA obligations may need to be retained for renewable energy and high efficiency combined heat and power facilities to ensure balanced market access and comparability of these generation sources to sustain state portfolio management objectives.

? Congressional enactment of a native load preference will complicate capital investment and the recovery of the costs of capital for competitive generation, and new transmission investments. If enacted, many of the regulatory gains of the past 15 years will be vitiated.

? Average power and fuel prices will increase especially for customers with lower load factors and rigid dispatch requirements. In dense urban areas, higher demand and energy charges will appear during peak demand periods.

RTOs

? RTO proceedings and individual case filings before Ferc will become the major policy fora in the Midwest, Southeast and West rather than proposed rulemakings over the next three years. The proposed change on scope and regional configuration has major implications for Southeast markets where a multitude of RTOs with ITCs could proliferate.

? Grandfathering of existing interconnection and transmission agreements is still left unclear, and could have major implications for existing project financings.

? Five RTOs look like they will settle on ten nationwide. At least a minimum of three RTOs appear likely in the Southeast, with potentially a dozen ITCs within the RTOs nationwide. The Southeast alone faces at least ten configuration alternatives pending as a possibility. This is stimulated by the subtle shift away from scope and regional configuration in the Ferc RTO requirements.

? The adequacy of incentives for investment in infrastructure ranging from the deficiencies of locational marginal pricing (LMP) and whether increases in transmission capacity will devalue FTRs for the long-term require thoughtful examination. These may foster a divestiture/acquisitions market for transmission and a realignment of transmission as a separate business pursuit.

Markets

? State fora will need to explore new regulatory issues of: affiliate regulation and reporting, stranded asset recovery for IPPs, behind-the-meter regulation, competitive bidding for new generation and contract resources, improved economic dispatch (including least emissions criteria), metering data availability and bias, and plant life retirements if state regional committees are to become credible players.

? Since markets/regulation are under challenge as to their viability, can they be relied upon to protect capital investments of this magnitude? Infrastructure to support a base load/control vertically integrated model may not work. Stranded regulatory assets caused by market shifts in Ferc and state regulation create a stranded investment exposure that could pave the way over the next 5 years for a transition to efficiency, renewables, internal metering for load control, distributed generation, hydrogen and new fuels and technologies. These could become the dispersed ?wireless? ?killer apps? of the utility industry. The key issue is one of timing, removal of artificial barriers and capital formation.

? Natural gas infrastructure projects may be more readily developed and favoured by investors than electric generation or transmission until 2010. Gas investments and acquisitions will be favoured. Power projects may need a secondary finance market structure with government support to refinance extended debt for the longer term ? if long term power purchase agreements do not re-appear.

? New niches of service will proliferate as the decade for project financing is gripped by power restructurings and refinancings, selective renewable energy deals, transmission projects and natural gas pipeline and LNG infrastructure improvements, and specialised funds. Demand response programmes that pay for LSE or ISO/RTO demand reductions will grow, and create new financing and structural challenges to implement.

Legal

? A continuing lack of clarity over jurisdiction is troubling as almost half the states raise questions on jurisdictional aspects of the current Ferc activities ranging from bundled retail transmission service to Ferc authority over resource adequacy and resource planning, and transfer activity over transmission assets.

? The role of ITCs and their lack of independence is a vexing problem, where many states favour a functional separation of ITCs and ITPs from within RTOs.

? Emissions trading and policies can add additional project revenues and will become a sound business practice without prescriptive requirements.

? Contract representations and warranties and legal opinions will need to be examined in light of these new risks for management.

The forward curve analysis for merchant power plants in the calculus of the risk management regime for project financing will be altered. Instead, the bank engineering report may need to be supplemented with additional analysis governing fuel pricing, transmission data analysis and availability for fuel and electricity, and environmental policy and emissions trading risks. More uncertainty will occur until 2005 as these issues are still measured, debated and resolved, and new rulemakings required by energy legislation occur. A certain level of conflict and inconsistency will reign as energy projects confront the most challenging project finance and risk management issues to survive. This will be the price for unraveling the merchant plant and marketing and trading paradigm through the provision of more flexibility in market design.