The US Congress changed some basic ground rules that have an effect on how gas and electricity are supplied in the United States.

The changes are part of a massive energy bill that President Bush signed into law on August 8. The bill repeals a 1935 law that was a barrier to utility mergers, strips away major parts of a 1978 law that was the original foundation for the independent power industry in the United States, and gives help to companies that want to build new transmission lines or LNG terminals.

Bye Bye PUHCA

One of the most significant parts of the bill is repeal of the Public Utility Holding Company Act, a 1935 statute that was originally supposed to make it difficult for utilities for form large multistate combines. The repeal takes effect in February 2006.

PUHCA threatens any company that owns or controls at least 10% of the voting stock of an gas or electric utility with extensive regulation as a “holding company.” Among other things, the company must get advance approval from the US Securities and Exchange Commission of its securities issuances and inter-corporate transactions. PUHCA also requires all utility subsidiaries of such a holding company to be in the “same area or region” of the country. Although this limitation had been applied liberally by the SEC, with the SEC stretching the statute in recent years to grant exemptions and to approve various utility mergers, PUHCA nonetheless prevented the formation of national utility companies.

PUHCA also presented an additional barrier for companies that are not already in the utility business to become active owners of utilities in more than one state. While companies like Enron and Dynegy managed to sidestep this restriction by reincorporating utilities they acquired in the state in which their utility subsidiary operated to take advantage of a “single state exemption” from PUHCA, this was not a viable strategy for many companies. The single state exemption is a rule that allows a company to own one or more utilities in a single state without being subjected to regulation as a utility holding company. Perhaps more importantly, PUHCA barred companies that own utilities from engaging in other lines of business beyond owning utilities and related energy companies. This restricted the universe of potential utility purchasers to companies that are already in the utility business — and to those who are willing to divest their other lines of business. As a result, companies like Berkshire Hathaway were limited to acquiring non-voting shares of utilities, or acquiring voting shares not exceeding 9.9% of the total. Similarly, private equity funds had to structure their investments in franchised utilities and independent transmission companies so that another entity exercised management control – an unappealing prospect for companies investing hundreds of millions of dollars in a business enterprise. Finally, while foreign companies were permitted to acquire US utilities, they had to submit to SEC regulation and limits on unrelated business activities.

PUHCA repeal does not mean an end to regulation. Utilities will be able to expand their operations without geographic restrictions, and private equity funds as well as other enterprises will have the opportunity to acquire utilities with fewer restrictions. However, this does not mean that companies are exempted from other regulatory constraints on utility ownership.

Virtually every US state regulatory commission has approval authority over acquisition of regulated utilities in their states.

The Federal Energy Regulatory Commission also has jurisdiction over acquisitions of utilities and utility assets of investor-owned utilities (except for utilities in the ERCOT region in Texas). The Department of Justice and the Federal Trade Commission retain jurisdiction over mergers, and the Atomic Energy Act, administered by the Nuclear Regulatory Commission, requires approval for acquisitions of utilities that own or operate nuclear power plants. The principal focus of the Department of Justice and FTC review, and one of the public interest factors in the FERC review, are the competitive effects of a proposed merger. Thus, proposed mergers of utilities with large portfolios of power plants in the same geographic market will continue be examined by multiple federal agencies to determine if they will adversely affect the relevant markets.

The likely effects of PUHCA repeal will be consolidation in the industry and entrance of new players as owners, although the pace of any change will be tempered by the need for multiple regulatory approvals of merger transactions. Financially-strong and well-managed utilities will be in the hunt for other gas and electric utilities that can provide strategic value or economies of scale. Among the open issues are whether many utility subsidiaries can be effectively managed by one centralized company, whether significant cost reductions can be obtained and passed on to ratepayers by eliminating duplicative back office, administrative, management and billing operations, and whether the local public utility commission can assure that reliable service can be maintained when control over the local utility resides with an out-of-state and more remote owner.

While companies owning only power plants — as opposed to transmission and distribution lines — have been exempted from PUHCA since 1992, PUHCA repeal should cause an increase in the number of power plants that are on the market, as “wires and pipes” utility companies expand their reach into geographic areas previously off-limits, and shed the generating assets of companies that they acquire. Also, PUHCA repeal greatly boosts the ability of transmission-only companies to acquire transmission systems anywhere in the United States and to construct new transmission lines without having to limit investments to passive ownership or small-percentage ownership arrangements.

Finally, at the same time that it repealed PUHCA (effective six months after enactment), Congress added the Public Utility Holding Company Act of 2005, a title bound to create confusion in documents that refer to PUHCA.

The new PUHCA responds to concerns that regulators would no longer have access to the books and records of companies that own or may now acquire public utilities. New PUHCA retains the same nomenclature of old PUHCA, defining a “holding company” as a company that owns 10% or more of the voting securities of a public utility. It requires parents and other affiliates of public utilities to make available to FERC and to state regulatory commissions the books, accounts, memoranda and other records of the parent holding company and other any member of the  holding company’s corporate family that are determined to be relevant to the costs incurred by a public utility company in a rate proceeding.

The authority to obtain and review books and records is also extended to affiliates of interstate natural gas pipeline companies, which previously were not subject to PUHCA at all. New PUHCA does require FERC to issue rules exempting from this new regulation companies that were exempted from regulation under old PUHCA — for example, foreign utility companies or owners of so-called qualifying facility projects.

PURPA Haze

The independent power industry in the United States got its start with help from a 1978 statute called the Public Utility Regulatory Policies Act, or PURPA. PURPA created a market for the output from two kinds of independent power plants — cogeneration facilities that produce two useful forms of energy from a single fuel, and small power production facilities that burn renewable of waste fuels. Utilities were required to buy electricity from such projects at their “avoided cost,” the cost the utility would have had to spend the generate the electricity itself. The projects are called “qualifying facilities” or “QFs.”

After many years of repeated assaults by the franchised utilities on PURPA, the utilities finally succeeded in gutting essential components of the original legislation.

The utility industry never liked the idea of being forced to buy power from competitors who use more efficient technology (cogeneration) or renewable fuels or waste (small power production) to generate electricity. Utilities also claimed that the states were setting rates above the cost of alternatives available to the utilities. On a prospective basis, the utilities will, for all intents and purposes, be freed from the federal requirement to buy power from new cogeneration facilities, and, in some sections of the country, from small power production facilities as well.

PURPA was a very significant milepost on the road to introducing competition to the generation markets in the United States. The statutory structure required FERC to issue rules to encourage more efficient and alternatively-fueled projects, and the states were to implement the federal rules. Once the states with high cost power and a shortage of generating capacity started to implement the federal rules in earnest, hundreds of projects and tens of thousands of megawatts were brought on-line. The utility industry, surprised by the surge of competition and fearful of building rate-based capacity before regulators that could disallow cost overruns and restrict returns, moved to build so-called independent power plants in competition with qualifying facilities, mostly in other utilities’ service territories, while fighting encroachment by cogenerators in their own. In addition, with the fledgling efforts to deregulate the industry in several states, state commissions encouraged vertically-integrated utilities to sell off their power plants in order to avoid the “stranded costs” that would result if they tried to sell power from expensive older plants in a newly competitive world. QF projects were forced to compete in this new environment.

With the industry moving rapidly toward a generation market functionally and legally separated from transmission and distribution, and with the movement toward the creation of retail choice in numerous states, utilities became reluctant to sign long-term contracts with qualifying facilities, even with the mandatory purchase obligation built into the law. State commissions were sympathetic to the claims of utilities that forcing them to sign such contracts would merely create more unrecoverable “stranded costs” because the utilities faced a loss of a retail market when retail choice kicked in. As a result, state commissions have generally failed to enforce PURPA with respect to new contracts for the past several years, and most independent generators have not had the financial strength or the time to devote to filing a court challenge to the state. This may help to explain the apparent acquiescence of the QF industry to the PURPA revisions in the energy bill, although the fact that the statute was amended rather than repealed made the changes easier to swallow.

Under the energy bill, existing QF contracts will be “grandfathered.” In other words, the commitments in the contract between a QF and a utility will not be affected by the legislation.

Moreover, the bill added a requirement for FERC to issue and enforce regulations to ensure that a utility purchaser will be able to pass through the costs associated with its QF purchases under a contract to its ratepayers, whether the contract is existing or new. This provision is supposed to discourage state commissions from allowing only a partial recovery of utility payments to QFs in retail rates. Not only will this protect utilities from potential losses, but it will also protect QFs that have so-called “regulatory-out clauses” in their contracts with utilities. A regulatory-out clause allows the utility to reduce payments to the QF if the utility cannot pass through all of the QF payments to its retail customers. Although the existing FERC regulations have been consistently interpreted to require passthrough of payments by the courts, the regulations themselves are not so specific on the point.

The bill is silent about the impact of amending an existing QF contract. However, if a QF and a utility agree to amend the contract, there should not be an adverse impact on the QF, whether or not the amendment substantially modifies the existing contract. The QF would remain exempted from federal and state rate regulation. Depending on the language of FERC’s new regulations that will require state commissions to let utilities pass through QF payments to ratepayers, it may be prudent to get the state commission’s blessing for the amendment before it becomes effective to ensure that the state will not be able to challenge the amendment in the future.

Unlike the language of the PUHCA section of the bill, the Congress does not simply repeal PURPA. Rather, it directs FERC to examine regional power markets and determine if the particular market is workably competitive. If it is workably competitive, then FERC can end any obligation by utilities in that market to purchase power from QFs or to sell backup power services to QFs. If the regional market is not workably competitive, then the utilities’ obligation remains in effect. A workably competitive market is independently run and has one of two features. Either the QF must have nondiscriminatory access to real time, day-ahead, and long-term capacity markets, or a QF in a regional transmission organization must have a meaningful opportunity to sell capacity and energy on a competitive basis to customers other than the QF’s interconnecting utility.

In regions where regional transmission organizations are in place, like PJM and the New England ISO, FERC is expected to remove the purchase and sale obligations from utilities. This would apply only to new QF contracts. In many other regions, however, conditions do not yet exist for FERC to be able to make that finding.

In addition, entities that want to become qualifying cogeneration facilities and that did not file for QF status before August 8, 2005 will be subject to far more stringent requirements before they will be certified as QFs.

A utility does not have to purchase power from an entity that was not already a qualifying cogeneration facility before August 8, 2005 unless the new cogeneration facility satisfies the more stringent requirements. FERC has 180 days to enact rules that explain the new requirements. The most significant new requirement is that the electrical, thermal and chemical output must be used fundamentally for industrial, commercial or institutional purposes and not be intended for sale to an electric utility. This will drastically limit the available electricity for sale to a utility and will require that the economic viability of the facility be determined by the purchases by the industrial host, not the utility. Consequently, it is unlikely that a significant number of new cogeneration QFs will be certified.

On the other hand, no new regulations are required for small power production facilities, so the utility purchase obligation will remain for existing and new small power production facilities, unless the FERC finds that the region is workably competitive. The same result applies for existing cogeneration facilities.

Finally, utilities will be allowed to own 100% interests in qualifying facilities. FERC’s current rules limit a utility’s ownership to 50%. Lifting this restriction will probably encourage utilities to acquire additional interests in QF projects, and there will be fewer partnerships of the kind that utilities entered into in the past with non-utility interests in order to acquire QF projects without running afoul of utility ownership limits.

Clearly, the financial prospects are better for small power producers — like developers of windpower and biomass projects — than for cogenerators. Even if FERC removes the federal mandatory purchase obligation in a particular region of the country, small power producers can still benefit from the renewable portfolio standard that may be in place at the state level and that imposes on the utilities a minimum percentage of renewable generation to be included in their overall generation mix.

Wheeling and Dealing in Transmission

FERC has exercised siting authority for interstate gas pipelines for years. Such pipelines are regulated only by FERC. By receiving a certificate from FERC under the Natural Gas Act, a pipeline company is authorized to construct and operate the pipeline and related facilities along the entire right-of-way. In addition, a certificated pipeline is granted the power of eminent domain to acquire any property rights needed to develop the line that cannot be obtained through negotiations with the property owners.

In contrast, electric transmission line permitting has been exclusively a state function to date, and construction of transmission lines ordinarily requires a utility or private transmission developer to obtain a “certificate of public convenience and necessity” from each state or states in which the lines would be located. The state power of eminent domain, which is especially important for developing continuous transmission corridors, is usually available only to the local franchised utility, so that transmission-only companies and non-utility generators that want to develop their own lines face significant obstacles if private landowners are unwilling to grant needed rights-of-way. An additional problem has been the reluctance of state commissions to authorize the construction of a transmission line when the line will be used solely to move power through the state to load centers in the state next door.

To address these problems and permit the development of transmission that benefits users of the multi-state US power grid, the energy bill directs the US Department of Energy, within one year, to designate areas where transmission is needed.

If an application is submitted to FERC to construct transmission lines in a designated transmission corridor, then the FERC must determine if the state or states in which the lines would be constructed lacks the authority to authorize transmission construction, or if its approval process fails to take into account the benefits that would accrue to other states, or if the fact that the applicant is not a utility that serves end users in the state prevents it from receiving state siting approval. If FERC finds that one or more of these obstacles is present, or if it finds that the state has failed to approve a transmission project for more than one year or has conditioned its approval so as to make the proposal economically infeasible, then FERC can authorize construction of a transmission project in a designated corridor (except in the ERCOT region of Texas).

In addition, if FERC grants a transmission permit, then it can authorize the permit holder to acquire the rights-of-way needed to construct the project upon the payment of “just compensation” as determined by a federal district court, under procedures similar to those currently available to pipeline companies that obtain a FERC certification to develop interstate pipeline projects.

The new siting authority also puts pressure on federal agencies that have permit or environmental review authority over the development of transmission projects by granting the Department of Energy authority to ensure that all such federal agencies complete their reviews within one year of the submission of a completed permit application, or as soon afterward as is practical. In addition, if a federal agency denies a needed authorization to construct a transmission project or fails to act within the deadline, then the applicant may appeal to the president of the United States, who may issue the authorization.

Will this new siting authority be enough to add the needed wires?

The jury is out, because the law does not exempt transmission developers from extensive environmental review, including compliance with National Environmental Policy Act, the Endangered Species Act, and the Federal Land Policy and Management Act. Moreover, to authorize transmission line construction, FERC must make numerous findings about the public benefits of the line, including its consistency with national energy policy. In many instances the development of new transmission lines has been hindered by permit-related delays, by the exclusive focus on local, rather than regional or national benefits by permitting authorities, and by the unavailability of eminent domain rights for non-utility developers. However, many transmission projects, especially those involving the development of mine-mouth coal and wind energy projects located hundreds of miles from load centers, have been hindered more by the cost of transmission construction or upgrades necessary to deliver their power to load than by siting considerations. As demonstrated by FERC’s recent decision to assign the costs of the proposed Tehachapi  “trunkline” transmission line in California exclusively to wind projects that would tie into the line, rather than treating these costs as part of the system costs to be borne by all users of the grid, transmission pricing policies will continue to play a key role in the development of transmission projects.

Nevertheless, for the first time, the federal government will have the authority to override parochial state transmission permitting policies. It gives utilities, transmission companies and power plant developers the ability, under an admittedly cumbersome and time-consuming process, to overcome obstacles to construction. The threat to resort to federal authority may make states and private property owners more willing to approve new wires and reach voluntary accommodations with transmission project developers.

Closing the Generation Gap

Congress made two significant changes to the part of the Federal Power Act that gives FERC jurisdiction over sales of, and changes of control over, utility assets and the utilities that own them.

The first is an increase in the minimum dollar value of such “jurisdictional facilities” before FERC approval is required for a sale. The minimum value was increased from $50,000 to $10 million. Thus, smaller transactions involving small facilities can avoid the requirement to obtain FERC approval.

The second change is to give FERC, for the first time, authority over the sale or change of control over generation-only transfers. Under existing law, FERC lacked jurisdiction over a sale or disposition of a generating asset, unless jurisdictional facilities were involved. Often, this limitation did not limit FERC’s authority over the transfer, because interconnection lines and transformers were often part of a sale of a generating plant, and FERC would assert jurisdiction over the entire transaction on the basis that a component of the transaction contained jurisdictional transmission facilities. However, in recent years, utilities have sold thousands of megawatts of generation — Southern California Edison Company and Pacific Gas & Electric Company sold about 10,000 MW this way in the late 1990s — without seeking FERC approval by making sure that the sale of generating assets did not include any equipment that could be characterized as transmission equipment.

FERC Chairman Joseph Kelliher had expressed concern about this “loophole” and lobbied hard to get this merger provision into the final version of the bill. The merger authority amendment takes effect in early February next year (six months after enactment).

I Can See Clearly Now

In response to allegations of market manipulation, false reporting of prices used for energy price indexing, and other activities that came to light following the California energy crisis, Congress extended FERC’s authority to prohibit these practices (through market transparency rules) and increased the civil and criminal penalties to which those engaged in these practices are subject.

The energy bill prohibits the submission of false information relating to the price of wholesale power or interstate transmission to a federal agency, if the person providing the information knows it to be false and intends fraudulently to affect data being compiled by the federal agency.

The bill also codifies actions taken by FERC in the wake of the California energy crisis by prohibiting the use of “any manipulative or deceptive device or contrivance” — terms used in the 1934 Securities Exchange Act–by any entity in connection with the purchase or sale of power or transmission subject to FERC jurisdiction. The bill gives federal courts the authority to prohibit a person who has engaged in such practices permanently from serving as an officer or director of an electric utility or engaging in power sales or transmission activities subject to FERC jurisdiction.

The energy bill also significantly expands FERC’s authority by allowing the agency to impose stiff civil and criminal penalties on persons and companies that violate the Federal Power Act or FERC orders.

Natural Gas

The energy bill resolved a dispute between the federal and state governments in the United States by declaring that FERC has exclusive authority over the siting, construction, expansion and operation of liquefied natural gas facilities located both onshore or in state waters.

FERC will still have to consult with state and local governments, as the states retain certain rights under the Coastal Zone Management Act of 1972, the Clean Air Act and the Federal Water Pollution Control Act.

However, the most immediate effect of the decision in the energy bill to give FERC the final say over where LNG terminals get built should be the dismissal of a case — currently in a US appeals court — in which the California Public Utilities Commission is challenging a FERC decision that it has exclusive authority to allow construction of an LNG terminal by Mitsubishi and ConocoPhillips in Long Beach harbor.

The energy bill also names FERC the lead federal agency for purposes of the National Environmental Policy Act environmental review process. FERC will set a regulatory review schedule and prepare a single environmental review document, which will then be used as a basis for all decisions under federal law on applications for authorizations under the Natural Gas Act. The bill also sets firm deadlines for disposing of appeals under the Coastal Zone Management Act of 1972. The deadlines were needed because states have been able, in some cases, to delay approvals for new LNG terminals indefinitely by manipulating the CZMA appeals procedure.

The energy bill also codifies a FERC order in 2002 called the “Hackberry” decision. Hackberry set a precedent for private, non-open access LNG terminals to charge market-based rates. It also eliminated the requirement for tariffs or other terms and conditions of service to be filed with FERC or otherwise made available to the public.

Congress also recognized the potential for inconsistencies at LNG terminals that provide both open access service and private unregulated service. The bill bars owners of LNG facilities that offer open access service from passing through the costs of any new private, non-open access expansion capacity in the open access rates. Open access ratepayers are also protected from any degradation of service or discrimination in terms and conditions of service resulting from such private expansion capacity.

Finally, the bill authorizes market-based rates at natural gas storage facilities for new storage capacity placed in service after August 8, 2005. Until now, a gas storage company had to show that it lacks “market power” to get authority to charge market rates. Such a showing will no longer be required if FERC determines that market-based rates are in the public interest and necessary to encourage the construction of storage capacity in areas needing storage services and customers are adequately protected.

Given the plans of many LNG import terminal developers to use nearby underground gas storage facilities for additional storage capacity, this part of the bill provides a mechanism to better link the terms of service of the LNG import terminal with the associated underground storage service.