Grid system operators now hold the cards. That means a bidding war for talent and a new wave of mergers.

TBy issuing new rules for a Standard Market Design (SMD) for wholesale power, the Federal Energy Regulatory Commission (FERC) in all likelihood will usher in a new wave of utility mergers. But the pattern will differ from what we have seen in recent years.

The deals will center on the transmission sector, and take a horizontal shape, rather than vertical.

That's because the SMD will recast the value chain for the utility industry making the RTO (regional transmission organization) and the ITP (independent transmission provider) the Master of Ceremonies. It will create a war for talent among grid operators. It will convert transmission system operation into the engine that creates value in wholesale markets for energy and capacity.

At the same time, however, the outlook for utility deregulation at the retail level appears much less promising. The political backlash from California's failed experiment with electric competition, as well as the Enron scandal, leads regulators in other states to question the value of retail deregulation.

Yet this dichotomy between retail and wholesale deregulation will only reinforce my prediction of a new merger wave.

On one hand, FERC wants to promote price discovery and unfettered open access where the transmission owner and/or operator do not face energy price risk. Yet on the other, many state regulators do not trust wholesale competition to result in low or consistent prices to bundled customers, nor to result in adequate capacity reserves for system reliability.

This growing disconnect soon will encourage utilities to choose whether to remain in an integrated business regulated by two jurisdictions, or to become one of three types of a "pure play" energy business: a distribution business controlled by state public utility commissions (PUCs), a transmission-only business, or unregulated generation and other services business.

In fact, the philosophical differences between the separate regulatory jurisdictions for transmission (federal) and distribution (state) are diverging to the point that makes it difficult for companies to strike regulatory compacts that fit a consistent and focused corporate vision. The new rules make it clear that integrated utilities will need to be passive common carriers while being cost-effective providers of bundled services. Utilities have dealt with different compacts in the past, one struck with FERC, and others reached with one or more state regulators. Still, utilities in PJM and NY ISO, models for FERC's proposed rules, have had a higher propensity to merge than utilities in other regions.1 With the advent of successful independent transmission companies, transmission asset owners will soon have the opportunity to divest those assets at a reasonable return to investors, while consolidating distribution and retail services. Of course, the new FERC rules will not alter global competition for customers, markets, and resources. They will not change the fact that the utility industry is technologically mature and must learn how to survive in the information age. The pressures on companies to deal with these threats by consolidating through mergers will continue. Yet the FERC rules certainly will lead to a significant horizontal consolidation of operation and ownership in electric transmission.

A New Set of Risks

Already, FERC's Order 2000 has encouraged consolidation between the Midwest ISO and the Southwest Power Pool, along with various other forms of grid owner-operators, such as American Transmission Company, TransElect, Grid America, and TRANSLink. Other entities have been discussed in the Northeast, Southeast, desert Southwest, and Northwest. Last year, FERC suggested that there should be four RTOs across the United States, but has since backed away from that view. Now, however, with its SMD rule, FERC seeks a virtual equivalency to the four-RTO concept, with a requirement that all jurisdictional entities must turn over transmission grid operations to an independent transmission provider (ITP) that uses a standard market design. Other agreements for a standard tariff and reconciliation of "seams" anomalies, plus reciprocity across boundaries, will achieve the same result. FERC will get what it wants, but companies will have a somewhat greater choice on how to get there.

FERC's proposed rules, when successfully implemented, will force separation of business units and impose business-like thinking on management, to deal with such risks as:

• Locational pricing and new valuations for generation, transmission, and distribution assets;
• Arrangements with state regulators on retail rates, siting, and other issues, some of which will support RTOs and some will not;
• A new risk profile for the transmission business (Is it still a "core competency" for utilities?);
• A bidding war for talent among grid operators;
• Shrinking "headroom" between capped retail rates and costs of doing business;
• A loss of preference for assets dedicated to native load; and
• Higher risks associated with maintaining reliability of service.

Since system operation is the hub of energy and capacity markets and the value chain, any strategy to deal with these risks will involve corporate financial planning and raise a host of important issues. (See Sidebar, "Twenty-Four Questions")

Mergers on the Horizon?

Following a spate of merger transactions among utilities in the 1990s, there are no significant mergers pending in the industry today. That situation mirrors other industries, where uncertain economic conditions brought merger activity to a standstill.

Yet mergers have proved profitable in other industries, such as banks, airlines, and telecommunications.

With stock prices possibly reaching lows, assets may again become attractive. Utilities may gain special favor as dividend-producing investments in an uncertain and slow-growth economy. The generation business is struggling and trading at all-time lows, and surely that segment will see further consolidation.

If anything, FERC's proposed rules suggest that the electric industry will follow the natural gas model. Although the electric grid has important physical properties that differ greatly from natural gas, the structure can be made similar. Transmission and transportation can be independent from supply. End-use distribution can be centrally situated in the value chain.

Granted, the market-operation function is considerably more complex on the electric side, which has been a key reason for the length of time required to develop a standard design. Yet FERC now has provided the framework that allows flexibility in the form of independent transmission entities, while holding firm on what functions they will perform. This needed clarity should not only enable progress in the formation of an independently operated grid by fewer entities than today, but it will also stimulate important strategic thinking about the industry's future. New approaches to serving customers and building infrastructure may come out of this thinking, and that would be welcomed. In any event, an almost certain path will be renewed merger activity, including the consolidation of generator companies, the amalgamation of transmission-owning and operating entities, and the combination of distribution companies.

---

---

Rule: Utility Must Turn Over Operations to Independent Transmission Provider (ITP)

Q. If we hold onto our transmission assets, what is the best form of compliance: direct member of a Regional Transmission Organization (RTO), direct member of an Independent Transmission Company (ITC) under an RTO, employ an ITP only, or under contract?

Many factors to analyze:

• Confidence in operational abilities of the independent entity(ies)
• Cost of implementation, not likely the same for each option
• Span of control by new entity associated with each option
• Need to retain control area responsibilities
• Integration requirements differences/comparative analysis
• Effect of each option on the ability to achieve allowed rate of return
• Economies or dis-economies of scale associated with each option that would affect rates (grid management charge)
• How each entity would handle planning within regional construct
• Timetable for compliance and implementation (beginning with discussion about compliance with SMD with stake holders and state representatives within 30 days of final rule)
• Preferences of state regulator/stakeholders
• Interest of neighboring systems
• Potential for divesting assets at later date
• Interim approach of ITP versus RTO

Q. What are the financial implications of turning over system operations to an independent entity?

Key factors to analyze:

• Loss of dispatch control for energy and capacity
• Effect on owned generation in providing energy and ancillary services
• Effect on native load
• Effect on ability to compete in wholesale market
• Grid management costs versus internal staff reduction and other cost elimination
• Whether there will be issues of potentially stranded investment in own energy management, metering, AGC, OASIS, and other systems
• Whether or not state regulators allow transition costs in rates
• Contract terms with ITP (Standard RTO Operations Agreement versus an agreement with an ITC or ITP)
• Specific terms regarding the responsibilities and liabilities of each party
• Financial risk assessment should the RTO, ITC, or ITP fail
• How SMD and the new Network Access Tariff will change loading on transmission system (Will reliability upgrades be required? Who should pay for those upgrades?)

Rule: ITP Must Offer a New Network Access Service (NAS)

Q. How will NAS be accommodated with grandfathered network and point-to-point service? For example, what NAS service must the transmission owner take to meet contractual obligations to serve pre-Order 888 contract customers?
Q. What analysis will be required to reform retail rates, e.g., T&D split?
Q. What performance/incentive rate proposals should be made?
Q. Will cost shifting adversely affect native load and create rate-ceiling problems?
Q. What state rate proceedings will be triggered by the NAS?
Q. What pricing model is needed to maintain revenue neutrality with respect to transmission revenue?

Rule: ITP Must Employ Standard Market Design

Q. What regional exceptions are absolutely necessary for the viability of SMD? Q. What issues should be discussed with stakeholders and state representatives within 30 days of the final rule?
Q. How will SMD affect the competitiveness of native generation?
Q. How will SMD impact the calculation and recovery of energy and capacity charges under retail rates?
Q. How will SMD affect the value of specific transmission assets?
Q. What and how should existing transmission rights be allocated under SMD?
Q. What are the risks and costs of congestion not hedged by existing transmission rights?
Q. How will the distribution utility become a prudent energy purchaser? Will regulators in the future compare long-term contracts signed today against spot market prices in the future?
Q. Will the 12 percent capacity reserve requirements of SMD add to costs of serving load relative to today? Will the state(s) have more stringent capacity (reliability) requirements?
Q. What agreements for market operations and reliability are required to enable a smooth transition from an independent control area to a regional one?

Choice: Should a Utility Divest Grid Assets?

Q. Is ownership of a regulated asset a core competency?
Q. What are the attributes of the preferred buyer, e.g., ITC versus any buyer?
Q. What are the shareholder return consequences of divesting transmission assets?
Q.Are there bond covenants that make divestiture unattractive?
Q. How would FERC/state regulators treat the sale? What would the regulators allow the purchaser to assign as rate base?
Q. What conditions in the sale would be necessary to protect customers and gain regulatory approval? -L.O.

Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.