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Notice

Removing Obstacles To Increased Electric Generation and Natural Gas Supply in The Western United States; Order Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States and Requesting Comments on Further Actions to Increase Energy Supply and Decrease Energy Consumption; Before Commissioners: Curt Hébert, Jr., Chairman; William L. Massey, and Linda Breathitt.

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Start Preamble Issued March 14, 2001.

Introduction

In this order, the Commission announces certain actions it is taking within its regulatory authorities under the Federal Power Act, the Natural Gas Act, the Natural Gas Policy Act, the Public Utility Regulatory Policies Act, and the Interstate Commerce Act to help increase electric generation supply and delivery in the Western United States,[1] in order to protect consumers from supply disruptions. In light of the severe electric energy shortages facing California and other areas of the West in recent months, which are likely to prevail into the foreseeable future, the Commission has examined all of its rate and facility certification authorities in the areas of electric energy, natural gas, hydroelectric and oil to determine how it can help increase electric energy supply.

We have examined both electric supply-side and demand-side actions that need to be taken, as well as how to best assure the input of natural gas needed for electric power production. While our authorities are somewhat limited, we are taking steps to immediately help increase supply from existing power sources and to provide regulatory incentives to build new electric and natural gas infrastructure.[2] California's dependence on electric generation and natural gas resources located in other states and the impact that California's energy shortage is having throughout the Western Interconnection underscores the regional, interstate nature of the energy marketplace.

The Commission recognizes that the actions announced here, by themselves, will not solve the electricity crisis facing California and other areas of the West and will not prevent electricity blackouts in the summer of 2001. However, we wish to elicit whatever additional electric supply there is from existing resources and, equally important, to identify and work constructively on medium and longer term solutions, including new infrastructure that can help avert future recurrences of the current electric supply shortage in the West. Of course, our efforts are only a small part of the electric supply picture, since State regulators, not this Commission, have siting authority for electric generation and transmission facilities, as well as for natural gas local distribution facilities. Moreover, State regulators have the most significant authorities to encourage demand reduction measures. Accordingly, as discussed below, the Commission intends to meet with State regulators this spring.

In summary, this order provides for or describes the following actions effective on the date of issuance of this order. Except as specifically noted in the text, Start Printed Page 15859these actions expire on December 31, 2001:

  • Requires the California ISO and transmission owners within the WSCC to prepare and file a list of grid enhancements that can be completed in the short term.
  • Extends and broadens the temporary waivers of operating and efficiency standards, and fuel use requirements, for qualifying facilities through December 31, 2001.
  • Waives prior notice requirements and grants authorization of market-based rates, through December 31, 2001, for wholesale power sales from generation used primarily for back-up and self generation and located at businesses within the WSCC.
  • Authorizes wholesale customers and retail customers (where permitted under state rules) who reduce consumption to resell their load reduction at wholesale at market-based rates.
  • Waves the prior notice requirements for wholesale contract modifications to facilitate demand-side management.
  • Where there are cost-based wholesale rates in effect subject to a formula, the Commission will permit DSM costs to be treated consistently with other types of incremental and out-of-pocket costs.
  • The Commission has realigned its staff to be able to respond as quickly as possible to applications for new gas pipeline capacity.
  • The Commission staff will hold a conference this spring to discuss with hydroelectric licensees, agencies, and others the possibility of increased generation consistent with environmental protection.
  • The Commission urges all FERC hydroelectric licensees in the WSCC to immediately examine their projects and propose any efficiency modifications that may increase generation. The licensees should detail to the Commission any environmental impacts, including impacts from changes to discretionary operations, that could occur if there are changes resulting from proposed efficiency modifications.

The Commission seeks comment on the following proposals, which, unless specifically noted otherwise, would apply through December 31, 2001:

  • Premiums on equity returns, and 10-year depreciation, for projects that increase transmission capacity in the short term.
  • Premiums on equity returns, and 15-year depreciation, for transmission upgrades involving new rights of way that can be in service by November 1, 2002.
  • Premiums on equity returns for new interconnection facilities required for new entrants that can be in service by November 1, 2002.
  • Allowed revenue recovery for non-capital intensive expenditures made to increase transmission capacity on constrained interfaces.
  • Allowing rolling in of interconnection and upgrade costs associated with new supply, rather than directly assigning such costs to the generator.
  • Use of the interconnection authority contained in section 210(d) of the Federal Power Act to help alleviate impediments to electric supply reaching load.
  • Waiving the blanket certificate regulations to increase the dollar limitations for natural gas facilities under automatic authorization to $10 million and for prior notice authorizations to $30 million.
  • Offering blanket certificates for construction or acquisition and operation of portable compressor stations to enhance pipeline capacity to California.
  • Offering rate incentives to expedite construction of projects that will make additional capacity available this summer on constrained pipeline systems.
  • Allowing for greater operating flexibility at licensed hydrolectric projects to increase generation while protecting environmental resources.

I. Electric Generation and Transmission

The problems that California and the West have been experiencing with regard to electricity supply/demand imbalances and high market prices result from transmission constraints, generation inadequacy, and inadequate demand-side response. The actions described in this section address those factors.

A. Electric Transmission Infrastructure

Our December 15 Order on California electricity issues [3] implemented several immediate measures designed to stabilize the California markets. The elimination of the requirement that the investor-owned utilities (IOUs) sell all of their resources into and buy all of their requirements from the California Power Exchange (CalPX) allowed the IOU's to use their 25,000 MW of generation to serve their load without buying it at spot prices. This, in conjunction with the elimination of the Cal PX's single price auction at bids above $150, terminating the Cal PX's rate schedule entirely as of May 1, 2001, and implementing a 5% bandwidth for scheduling error in the Cal ISO's real time market was intended to provide immediate help.[4] Nevertheless, the crisis in California's electricity power supply system continues.[5] Stage 3 System Emergencies (declared when operating reserves are below 1.5 percent) have become the order of the day and the threat of rolling blackouts is fast becoming routine. While our December 15 Order eliminated the chronic over-reliance on spot markets to meet the electric needs of 32 million Californians, we are now faced with the hard work of building up the infrastructure of the Western grid.

Our November 1 Order on California electricity matters [6] discussed at considerable length many long term measures which need to be implemented with speed and deliberation in order to restore safe, reliable and economical power to the consumers in the West. As a complement to the vital initiative of increasing generation supply, we focus today on where we believe this commission can have the greatest impact—fostering the installation of critical transmission investment.[7] There is little doubt that the supply shortage is real and that we must take bold action. Interconnecting new supply to the bulk power system, upgrading that system to ensure that the new supply can reach load reliably, and eliminating bottlenecks which prevent maximum utilization of existing supply must be accomplished efficiently and expeditiously. With this in mind, we propose herein a package of economic incentives aimed at ensuring the timely completion of upgrades to the Western grid needed to better use existing supply and to accommodate new supply. We also propose that these incentives be Start Printed Page 15860implemented by way of a limited Section 205 filing which would not open up existing rates to review.

First, some grid enhancements may be underway or may not require initial siting and acquisition of rights of way, such as reconfiguring or reconducting existing lines or using existing towers for additional circuits. These types of projects offer the greatest potential for improving grid capacity at present constraints in the shortest period of time. We direct the Cal ISO and the transmission owners in the WSCC to prepare and file, for informational purposes, a list of such projects within 30 days of the date of this order. The filing should clearly describe each project, its impact on grid capability as present constraints, the status of state certification if necessary, its cost and a definite completion date.

In order to provide incentives for the construction of such projects at the earliest date possible, we propose to give transmission owners of projects that increase transmission capacity at present constraints and can be in service by July 1, 2001, a cost-based rate reflecting a 300 basis point premium on equity and a 10-year depreciable life. Those that can be in service by November 1, 2001 will receive a cost-based rate reflecting a 200 basis point premium and a 10-year depreciable life. In order for our incentives to have their desired effect as quickly as possible, transmission owners must be given certainty at the outset. Therefore, we propose that, in implementing the equity premium, would use a uniform baseline cost of equity for all jurisdictional transmission providers in the WSCC of 11.5%. This figure is in line with the most recent allowance we have approved for a western utility.[8] Accordingly, we proposed that projects which qualify for a 300 basis point premium would be afforded a return on equity of 14.5%.

Second, for system upgrades that involve new rights of way, add significant transfer capability and can be in service by November 1, 2002, we propose to permit transmission owners a cost-based rate reflecting a return of equity of 12.5% (a 100 basis point premium) and a 15-year depreciable life.

Third, we propose that facilities needed to interconnect new supply to the grid which go in service as required to accommodate the in-service date of the new entrant will also be afforded a cost-based rate which reflects a return on equity of 13.5% (a 200 basis point premium) if in service by November 1, 2001 and 12.5% (a 100 basis point premium) if in service by November 1, 2002.

Fourth, to the extent that transmission owners can increase transmission capacity on constrained interfaces without capital intensive expenditures by, for example, installing new technology on existing facilities to better control voltage and power flow or by implementing new operating procedures, we propose to allow them to increase the revenue requirement of their network service rates to ensure that each additional MW of capacity will generate revenues equal to the provider's current firm point-to-point rate.

In an effort to provide the incentives to promote needed infrastructure without economically disadvantaging new supply, we request comment on whether to assign the cost of any interconnection or system upgrade to a particular load or supply or, alternatively, to roll these costs into the average system rate. We recognize that it has been our policy to allow the cost of interconnection and the cost of certain incremental system upgrades to be borne by those loads or supplies on the margin. However, the entire Western Interconnection is in a state of stress and there may soon be no power available at any price. In these circumstances, it is imperative that our pricing policies minimize the cost of entry upon individual entrants.

B. Extension of Waivers for Qualifying Facilities

In an order issued December 8, 2000,[9] the Commission granted certain temporary waivers of operating and efficiency standards for Qualifying Facilities (QFs) to allow increased generation. The temporary waivers were to expire January 1, 2001, but were subsequently extended through April 30, 2001.[10] Because of the capacity shortages in California and other areas in the West now and in the foreseeable future, we find good cause to extend those temporary waivers through December 31, 2001 and apply them to the entire WSCC.[11]

In the December 8 Order, we stated that section 292.205(c) of the Commission's regulations allows the Commission to waive any of its operating and efficiency standards for qualifying cogeneration facilities “upon a showing that the facility will produce significant energy savings.” [12] We find that the same factors of serious supply and demand imbalances that supported our waiver in the December 8 Order continue to exist. Therefore, consistent with the goals of PURPA, we find that extending such waiver through December 31, 2001 will provide for improved reliability of electric service by increasing the availability of needed capacity.[13] As in the December 8 Order, we will waive the operating and efficiency requirements to allow qualifying cogenerators to sell their output above the level at which they have historically supplied this output to the purchasing utility. A facility's seasonal average output during the two most recent years of operation will define in historical output. We require that all additional output from the cogenerators be sold exclusively through a negotiated bilateral agreement at market-based rates. This arrangement will benefit both parties and help serve load and reserves in California and the WSCC at a time when generation resources are inadequate.

In addition, consistent with our action in the December 8 Order, we will extend through December 31, 2001, the waiver for the qualifying small power production facilities in the WSCC with respect to their fuel use requirements under section 292.204(b) of the Commission's regulations based on the finding that the situation in California and the interconnected WSCC presents evidence of “emergencies, directly affecting the public health, safety, or welfare, which would result from electric power outages”.[14] In granting this temporary extension of the waiver, we place the same restriction as detailed above and require that the small power QFs sell their excess production only to load located within the WSCC through negotiated bilateral contracts.

C. Additional Capacity From On-site Generation

Many businesses have installed generators at their business location to meet a portion of their own demands or to serve as a backstop to their purchase of electricity from the local grid. These generators may provide a ready source of generation capacity during periods when power markets are facing a Start Printed Page 15861temporary generation shortage.[15] In order to facilitate the use of existing on-site generators to meet demand, the Commission will adopt a streamlined regulatory procedure to accommodate wholesale sales from such facilities that will serve load within the WSCC. For the period beginning with the issuance date of this order through December 31, 2001, owners of generating facilities located at business locations in the WSCC and used primarily for back-up or self-generation, who would become subject to the Federal Power Act by virtue of sales of power from such facilities,[16] will be permitted to sell power at wholesale from such facilities to non-affiliated entities within the WSCC without prior notice under section 205 of the FPA. Pursuant to FPA section 205(d), we find good cause to waive the prior notice requirements for such sales. Further, the Commission hereby grants waiver of its regulations consistent with our orders on market-based rates,[17] and authorizes market-based rates during the identified time period, subject to the following requirements: The wholesale purchasers of power from such facilities must report to the Commission the names of each such seller from whom power was purchased, the aggregate amount of capacity and/or energy purchased from each seller, and the aggregate compensation paid to each seller.[18] To minimize the number of required reports, the purchaser may make one report for all purchases pursuant to this paragraph, and, if it otherwise files quarterly transactions summaries with the Commission, may include this report as a separate section of its transaction summary for the first calendar quarter of 2002. If the purchaser does not otherwise file quarterly transactions summaries, it should file this report with the Commission by April 30, 2002.[19]

This measure does not abrogate or supersede any existing contracts or obligations, exempt any person from existing environmental, safety, or reliability requirements, authorize the feeding of power into the grid where not otherwise authorized, authorize a retail customer to violate any rules or retail tariff provisions that have been properly imposed on the retail sales made to those customers, or impose new substantive obligations on any person. This measure only streamlines Commission filing requirements for certain actions that are otherwise agreed to among the relevant parties.[20]

With respect to interconnections necessary to accomplish sales described above, to the extent mutually-agreed upon interconnection agreements become jurisdictional through the use of the interconnection for a jurisdictional sale during the specified period, the Commission waives the prior notice requirement for those agreements for the duration of the interim period. Filing of such jurisdictional interconnection agreements may be postponed and made along with the reports of sales pursuant to the procedures discussed above.

D. Purchases of Demand Reduction

It is widely accepted that dropping even a few megawatts off the system at peak periods is more efficient and economical than the incremental cost of generating them. Demand reduction offers a short-term and cost-effective means to provide additional resources during times of scarcity. Therefore, the Commission will allow, effective on the date of this order, retail customers, as permitted by state laws and regulations, and wholesale customers to reduce consumption for the purpose of reselling their load reduction at wholesale. By providing additional load resources when generating resources are scarce, these “negawatts” should help maintain the reliability of the grid. To stimulate the development of this program, the Commission is granting a blanket authorization to allow these sales at market-based rates. We are granting blanket authorization consistent with our discussion concerning sales from generating facilities located at business locations and used primarily for back-up or self-generation. Consistent with our monitoring of generation sales at market-based rates, the Commission will require that similar information on these transactions be reported on a quarterly basis.[21]

These transactions are considered wholesale when they involve the sale for resale of energy that would ordinarily be consumed by the reseller. These transactions can occur in several ways. An aggregater can line up retail load to acquire enough negawatts to resell in a manner similar to what aggregaters do when they sell power to retail load under retail choice programs. In addition, wholesale and retail load with contract demand service could resell their contract demands if the value of power is greater than the value of consumption.

Our December 15 Order on California issues directed, as a longer-term measure, that the Cal ISO pursue establishing an integrated day-ahead market in which all demand and supply bids are addressed in our venue.[22] We seek comments on the desirability of accelerating action on this.

We realize that states play an important role in regulating retail electric service and that allowing retail load to reduce consumption for resale in wholesale markets raises legal, commercial, technical and regulatory issues. But, given the dire supply situation in California and throughout the WSCC, the Commission is Start Printed Page 15862compelled to explore every regulatory opportunity to help the market to operate more efficiently and to help ensure short-term reliability throughout the Western Interconnection. Moreover, safeguards may be needed to protect and enhance retail demand-side management (DSM) programs. Our intention is not to undermine existing state DSM programs or other state rules governing retail sales, but to promote complementary wholesale programs. Therefore, we request comments on how helpful this action is and how well it can be accomplished consistent with state jurisdiction over retail sales.

E. Contract Modifications to Promote DSM

Related to the section above, there may be opportunities for public utilities to make other types of demand-side arrangements with their wholesale customers. For example, some wholesale requirements customers may have the ability to enter into arrangements with their own retail customers to reduce load or obtain power from an industrial generator. Or, a partial requirements customer may have access to generating capacity on its own system. We want to ensure that public utilities will be able to work with their customers to negotiate mutually beneficial arrangements on short notice. Since time may be of the essence as these opportunities are discovered and negotiated, we find good cause to waive the FPA's prior notice requirement for any rate schedule amendments that may be required to effectuate these types of arrangements. Thus, to the extent a mutually agreeable DSM alternative changes the terms and conditions of a contract within our jurisdiction, we will grant waiver of the filing of prior notice of the change. This measure will be effective upon the date of issuance of this order. By December 31, 2001, the public utility supplier must amend the filed rate schedule. The filing must consist of a report containing the following information: the FERC rate schedule numbers, the loan reduction negotiated under the DSM arrangement (MW/MWh), total compensation, and the name of each affected wholesale customer.[23]

F. DSM in Cost-Based Rates

While most power sales are currently transacted under market-based rates, there are occasions when utilities continue to operate under cost-based rates. Often, these cost-based rates incorporate formulas that are intended to track the actual out-of-pocket (i.e., incremental) cost that was incurred to generate or purchase the energy. During periods of generation shortage, some utilities may be in a position to engage in DSM transactions with their wholesale and retail requirements customers in order to free up capacity for resale to neighboring utilities. These transactions will not take place unless any DSM expenditures can also be recovered under the rate formula, as are all other out-of-pocket costs. However, most rate schedules define out-of-pocket or incremental cost in terms of expenses incurred to generate power, rather than costs incurred to compensate a preexisting customer to reduce load. A few jurisdictional utilities have amended their cost-based pricing formulas to recognize the fact that DSM costs are a form of out-of-pocket or incremental cost.[24] In order to eliminate any disincentive to rely on DSM as a source of supply during generation shortages, we clarify that DSM costs should be treated consistently with all other types of incremental and out-of-pocket costs. This measure will be effective upon the date of issuance of this order.

G. Interconnections

Section 210(d) of the FPA authorizes the Commission, on its own motion, after it follows certain procedures, to issue an order requiring the same actions an applicant may request with respect to interconnections, namely:

(A) the physical connection of any cogeneration facility, any small power production facility, or the transmission facilities of any electric utility, with the facilities of such applicant,

(B) such action as may be necessary to make effective any physical connection described in subparagraph (A), which physical connection is ineffective for any reason, such as inadequate size, poor maintenance, or physical unreliability,

(C) such sale or exchange of electric energy or other coordination, as may be necessary to carry out the purposes of any order under subparagraph (A) or (B), or

(D) such increase in transmission capacity as may be necessary to carry out the purposes of any order under subparagraph (A) or (B).

We seek comments on whether the exercise of the Commission's authority under this section could help alleviate any existing impediments that may be preventing generating resources from reaching load. If the exercise of this authority may be warranted, we seek comments on whether the Commission could make some of the required findings generically for the WSCC region in order for the Commission to respond quickly if appropriate circumstances arise.

H. Longer-term Regional Solutions

This order focuses primarily on short term regulatory actions that this agency can take to improve energy supply conditions in California and throughout the Western Interconnection. Because of the emergency conditions confronting the West, we are proposing interim rate measures to stimulate much-needed investment in transmission and generation infrastructure. However, in the long term, we believe that decisions regarding investment in new electric and gas infrastructure—including appropriate incentives for such investment—should be approached from a regional perspective that recognizes the interstate nature of the wholesale energy marketplace. In Order No. 2000,[25] the Commission recognized that many of the economic and reliability issues confronting the electric industry could only to be addressed on a regional basis. The current supply and demand electricity crisis in California is no exception. Any long-term solution to address the crisis and, more importantly, to prevent its recurrence, must be developed on a west wide basis, with appropriate input from all of the affected states. Recent events have demonstrated the regional nature of the electricity markets in the West. Problems of inadequate generation supply and poor demand responsiveness are made worse by localized electric transmission and gas pipeline capacity bottlenecks and by fragmentation of Western market rules. A west wide RTO, or a seamless integration of Western RTOs, is the best vehicle for designing and implementing a long-term regional solution.

An RTO of sufficient scope and regional configuration would foster investment in new generation by providing open and fair transmission access. By eliminating transmission rate “pancaking,” the RTO could provide sellers and buyers throughout the Western Interconnection with Start Printed Page 15863additional trading opportunities. These opportunities should help the entry of additional generation supplies. An RTO of sufficient scope and regional configuration would make optimal use of existing transmission through regional congestion management, motivate needed facility expansion, and bring credibility to the sitting process through coordinated regional transmission planning. A west wide RTO could also implement a regional “demand exchange” program to reduce load when supplies are low. Importantly, a west wide RTO could develop uniform market rules that would facilitate regional trade, lower supply costs, and improve reliability.

We take this opportunity to reiterate that the Commission remains committed to the policy course laid out in Order No. 2000. We will continue to work closely with transmission owners, market participants, and affected state utility commissions to encourage the further development of RTOs. We intend to act expeditiously on the compliance filings we have received in order to provide guidance to the industry and certainty to the regional marketplace. Long term market solutions to the supply and demand problems which have confronted California and its neighbors throughout the Western Interconnection will require fully functional RTOs sooner, rather than later.

II. Natural Gas Pipeline Capacity

Natural gas is an important fuel source for electric generators. Recently, there has been a significant escalation in the market price for natural gas. There also are reports of pipeline capacity constraints in moving gas to where it is needed for electric generation. The Commission will do what it can to increase pipeline capacity where appropriate.

The Commission has several types of jurisdiction over new pipeline construction. In general, a natural gas company that wishes to construct and operate new pipeline capacity for the transportation of natural gas in interstate commerce must first obtain a certificate of public convenience and necessity under section 7 of the Natural Gas Act. In addition to its certificate jurisdiction, the Commission has authority, delegated by the Secretary of Energy, over the siting and construction of facilities for the import or export natural gas under Section 3 of the Natural Gas Act as well as authority under Executive Order No. 1045 to issue Presidential Permits for such facilities if they are located at the international border. Authority to construct interstate gas pipeline facilities may also be found in the Commission's regulations implementing Section 311 of the Natural Gas Policy Act of 1978. Under these regulations, facilities to transport gas on behalf of a qualified shipper can be constructed on a self-implementing basis, without prior Commission approval as long as they are constructed in compliance with applicable environmental requirements.

The Commission is continuing to examine its staffing resources and has realigned its environmental expertise in order to ensure that gas infrastructure projects that could serve, directly or indirectly, to increase energy supplies to California and the West are expeditiously processed. Having the hydro and gas environmental staff in the same office has allowed for the assignment of expertise to accommodate gas projects as they are filed. When certain expertise is required to prosecute an application expeditiously, the Commission has the ability to readily bring in, as an example, an individual with knowledge of historic preservation issues. In the last seven months, the Commission has issued certificates for three projects that could benefit the West.[26] Several more certificate applications are pending, and the Commission is committed to moving quickly on these projects too.[27]

Because the traditional process for obtaining a certificate for new construction can be expensive and time consuming for applicants, the Commission has recently adopted a number of methods to expedite the process. For instance, the Commission's regulations offer blanket certificates for eligible facilities. Facilities that are not eligible to be built under a blanket certificate may receive a “preliminary determination” resolving all nonenvironmental issues in the proceeding within 180 days of filing. The Commission also adds to pipeline capacity available for interstate service by issuing certificates of limited jurisdiction when the public interest requires.

In response to the present conditions in California and the West, the Commission has realigned its resources, including its environmental staff, as mentioned above, to allow it to respond as quickly as possible to any applications to construct new capacity. The Commission is actively considering what other actions the Commission may take and is soliciting comments on ways to expedite the approval of pipeline infrastructure needed to serve California and the West.

During this winter, natural gas pipelines, especially in the West, have for the most part been fully utilized. Planned maintenance of pipelines, and concomitant reductions in transmission capacity, usually occur during the spring and summer. The Commission is looking for ways to avoid reduction in the amount of capacity and gas supplies in California and the West during this period. For example, portable compressors may add additional capacity or relieve capacity constraints on pipeline systems this summer.[28] We will be receptive to proposals that achieve these goals. We will also be receptive to rate proposals that provide an incentive to expedite construction to add capacity or relieve capacity constraints on pipeline systems this summer.

In considering what actions it could take to expedite further its ability to respond to the present energy crisis in California and the West consistent with its environmental responsibilities, the Commission is also concerned that any actions that it approves should not come at the expense of reducing the quality of service to existing customers.

Of course, some actions the Commission takes to expedite new capacity for gas to serve California and the West may only be effective to the extent there is available local distribution capacity to deliver gas downstream of the interstate pipeline. The availability of sufficient local take-away capacity, however, is a matter that is within the control of the states rather than of this Commission. We ask that the pipelines coordinate their efforts Start Printed Page 15864with local distribution companies, public utilities and state officials to ensure that the additional capacity on the interstate pipeline will be able to get to all entities (e.g., LDCs, generators, industrials) that need the gas supply.

Accordingly, the Commission requests the views of interested persons on how it might further exercise its authority over new pipeline construction to alleviate the present crisis. In particular, the Commission solicits the views of interested persons on the following proposals:

(1) Waiving the blanket certificate regulations to increase the dollar limitations for facilities under automatic authorization to $10 million and for prior notice authorizations to $30 million;

(2) Offering blanket certificates for construction or acquisition and operation of portable compressor stations to enhance pipeline capacity to California.

(3) Offering rate incentives to expedite construction of projects that will make additional capacity available this summer on constrained pipeline systems.

The Commissions' current policy of allowing rolled in rates for facilities built under the current blank authorization of $20.6 million or less would continue to apply. However, we request comments on whether blanket authorizations exceeding $20.6 million should also be rolled in.

III. Hydroelectric Power

Hydropower is a critical component of the Western states' generating assets, particularly in the Northwest. While approximately 40 percent of the total capacity in the 11-state WSCC is hydropower based, hydropower accounts for fully 65 percent of the Northwest generation. The Commission regulates 326 projects in the WSCC with a combined total capacity of 24,600 MW. Clearly any action taken to enhance the generation from these projects, consistent with protecting critical environmental resources, can improve the energy picture for the Western states. The current hydrologic conditions, however, are not conducive to maximizing hydropower generation during the summer of 2001.

General practice in the region calls for the coordinated efforts to fill hydropower reservoirs by the beginning of the summer peak electricity season by depending as much as possible on non-hydropower generation resources during the winter off-peak season. In plentiful water years, the Pacific Northwest is able to export hydropower to the southern part of the region during the summer and import fossil-fueled generation during the winter from the south to help meet off-peak loads and allow reservoir storage to refill for the next peak cycle. This coordinated effort has been hampered recently because demands within the Northwest restrict the amount of power available for export, and hydrologic conditions have hampered reservoir replenishment.

Forecasted river flows for spring and summer 2001 indicate below average flows across the Pacific Northwest and California. These predictions are based on past precipitation amounts, existing reservoir and river levels, and forecasted precipitation. Precipitation in the Northwest fell to low levels in November and December 2000, raising concerns about available hydropower. Stream flow conditions likewise fell to low levels in early January. Although the situation has improved recently, particularly in California, some parts of the Pacific Northwest, such as the upper Columbia River region, are still forecasted to have drastically low stream flows.

Where operation of hydroelectric facilities would affect flow-dependent environmental resources, the Commission's licenses have included operating constraints, such as requirements for minimum stream flow, minimum reservoir fluctuation, run-of-river operating mode, ramping rates, and flood control. Such measures serve to protect resources including resident and anadromous fish, water quality, recreation, municipal and industrial water supplies, and agricultural resources. These operating constraints act to reduce the energy production, peaking capacity, and other power benefits of hydropower projects. Granting some relief from these operating constraints would provide power systems with greater flexibility to meet power demands in the West.

Modification of these operational constraints on the currently licensed projects has the potential to increase generation from existing hydroelectric facilities, provide additional power during peak-load periods, and increase the ability of projects to provide ancillary services to the power system. Of the 326 projects licensed by the Commission within the WSCC, 200 have provisions that limit operational flexibility. These 200 projects represent a total capacity of 21,000 megawatts. Greater flexibility in the dispatch of this capacity, consistent with protecting environmental resources, could act at critical times to enhance the reliability of the system.

Modification of these operating constraints, however, would need to be done in a way that balances the generation improvements with protecting the environment. Before making changes to specific project licenses, the Commission would need to work closely with federal and state agencies to ensure that environmental resources, including species listed under the Endangered Species Act, are protected. This is consistent with the President's February 16, 2001 Memorandum to the Secretaries of Defense, Interior, Agriculture, and Commerce and the Administrator of the Environmental Protection Agency, which states:

I hereby direct all relevant Federal agencies to expedite Federal permit reviews and decision procedures with respect to the siting and operation of power plants in California. All actions taken must be consistent with statute and ensure continued protection of public health and the environment while preserving appropriate opportunities for public participation.

In addition, Commission review of licensed projects indicates that many hydropower projects are potentially capable of more fully using the available water resources to contribute to the electric capacity and energy needs. Existing projects are capable of improvements in these principal areas: (1) Addition of new capacity units, (2) generator upgrading through rewinding, (3) turbine upgrading through runner replacement, and (4) operational improvements through such means as improving coordination of upstream and downstream plants, increasing hydraulic head, and computerization. The Commission encourages all licensees to immediately examine their projects and propose any efficiency modifications that may contribute to the nation's power supply.

In order to expedite review of particular projects with the potential for increased generation, the Commission staff will hold a conference to discuss with agencies, licensees, and others, methods to address environmental protection at projects while allowing for increased generation. We expect to hold a staff conference as soon as possible this spring. Notice of the location and time of the meeting will be published.

Finally, the Commission seeks comments on ways to allow for greater operating flexibility at Commission-licensed hydropower projects while protecting environmental resources. Comments should consider: (1) Methods for agency involvement, (2) ways to handle and expedite Endangered Species Act consultation, (3) criteria for modifying licenses, and (4) identification of processes that could be Start Printed Page 15865implemented to provide efficiency upgrades.

IV. Oil Pipelines

Although oil and oil products are not used significantly for electric generation in the West, there are some generators that rely on such products. The Commission has jurisdiction under the Interstate Commerce Act (ICA) over the rates and charges of pipelines engaged in the transportation of oil and oil products in interstate commerce. The ICA requires that all pipelines charges just and reasonable rates for their service, provide and furnish transport upon reasonable request, and establish reasonable through routes with other carriers. The ICA prohibits pipelines from receiving rebates for service provided or making or giving undue preferences or advantages to shippers.

The Commission has no authority under the ICA to require certificates of public convenience and necessity as a basis for starting operations. That authority rests with local jurisdiction. Since the Commission has no authority over construction of oil pipelines, courts have held that environmental issues are separate from the rate issues over which the Commission has jurisdiction, and the Commission thus has been relieved of any responsibility under the National Environmental Policy Act. The Commission also has no authority over abandonments of service or authority to order extension of lines.

Following enactment of the Energy Policy Act of 1992, the Commission provided an indexing, or a price cap, methodology as a simplified method for oil pipelines to change their rates. The index approach has simplified the filing of rate changes. The Commission in recent years has also concluded that use of the term contracts and differential pricing to allocate risk is permissible under the Interstate Commerce Act to advance a number of innovative pricing proposals. The Commission will explore with oil pipelines other types of innovative proposals that could lead to ensuring an adequate flow of petroleum product into the California market.[29]

Request for Comments/Conference

The Commission seeks the views of industry participants, organizations, and state regulatory authorities on the actions and proposals identified herein, and on what other measures the Commission and others could take to assist in improving the supply/demand balance in California and elsewhere in the West.

We request that any comments be submitted to us by March 30, 2001. Such comments should be concise and focused. Interested persons should submit an original and 14 copies of any comments to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, and should reference Docket No. EL01-47-001.

Finally, the Commission intends to hold a one-day conference with state commissions and other state representatives from Western states to discuss price volatility in the West, as well as other FERC-related issues recently identified by the Governors of Western states.[30] A Commission notice specifying the details of this conference will be issued in the near future.

The Commission Orders

(A) The California ISO and the transmission owners in the WSCC are directed to prepare and file in this docket, within 30 days of the date of this order, a list of grid enhancements that could be made in the short term.

(B) Temporary waivers of certain operating and efficiency standards and fuel use requirements for qualifying facilities are granted to such facilities located in the WSCC through December 31, 2001, as discussed in the body of this order.

(C) For entities in the WSCC meeting the qualifications for on-site or back-up generation, and entities reducing load for resale, as discussed in the body of this order, and who satisfy the reporting requirements discussed herein, the following advance waivers and authorizations are hereby granted for the period beginning the date of this order through December 31, 2001:

(1) The prior notice requirement of section 205 of the Federal Power Act is hereby waived.

(2) Waiver is hereby granted for Parts 35, 41, 101, and 141 of the Commission's regulations.

(3) Authorization is hereby granted to issue securities and assume obligations and liabilities, provided that such issue or assumption is for some lawful object within the corporate purposes of the eligible entities, compatible with the public interest, and reasonably necessary or appropriate for such purposes.

(4) The full requirements of Part 45 of the Commission's regulations, except as noted, are hereby waived with respect to any person now holding or who may hold an otherwise proscribed interlocking directorate involving any eligible entity. Any such person instead shall file a sworn application providing the following information:

(a) full name and business address; and

(b) all jurisdictional interlocks, identifying the affected companies and the positions held by that person.

(D) The prior notice requirement for rate schedule changes to accommodate demand side management, as discussed in the body of this order, is hereby waived, conditioned on the public utility complying with the filing requirements set forth herein.

Start Signature

By the Commission. Commissioner Massey dissented in part with a separate statement attached.

David P. Boergers,

Secretary.

End Signature

Massey, Commissioner, dissenting in part:

Clearly the Commission should do whatever we can to help alleviate the continuing market crisis in the western states. This order is a very limited attempt to do so, but it makes errors of omission and commission from which I must dissent.

Let me first focus on the error of omission, or as I see it, “ignoring the elephant in the living room.” Today's order focuses on quick fixes to help narrow somewhat the gap between supply and demand in the west. I do not believe any of my colleagues seriously believes these measures will close that gap substantially. The California ISO projects deficiencies of up to 6,800 Mws for this summer. And I think that it is generally agreed that demand in California and elsewhere in the west is not responsive enough to prices. The Commission has previously found that the dysfunctional market in California is not producing just and reasonable prices. Addressing these problems is a long term endeavor. Unfortunately, market participants are forced to purchase in today's markets, and at prices that are arguably unlawful.

Last summer in our NSTAR and New York ISO orders, we found that these conditions—supply shortages and a lack of demand responsiveness—prevented these northeastern electricity markets from operating as typical competitive markets and that price mitigation was needed.[1] Yet today's order fails to address price relief in the short term for Start Printed Page 15866consumers in the western part of our nation where the same conditions exist and are much worse.

I am very concerned with the economic effects the current market meltdown is having. An article in yesterday's Wall Street Journal reported that the current western energy crisis could cut disposable household income by $1.7 billion and cost 43,000 jobs over the next three years in Washington state alone. Some fear that it could tip the region into a recession. Moreover, the current volatile and high prices, which will be worse by magnitudes this coming summer, are devastating consumer and investor confidence in a market based approach to electricity regulation. Over the past three months, I have attended and spoken at two separate conferences sponsored by the Western Governors Association dealing with these issues. Scores of market participants and western public officials spoke passionately and eloquently about the nature of the problems they face. Certainly the issue of supply is a big problem that must be addressed, but so is the issue of price. Without protection, there is huge concern about what the summer will bring in terms of high prices and volatility. If the west experiences another summer like the last, I fear for the future viability of this agency's policy favoring wholesale competition. The political viability of a market based approach for electricity may suffer irreparably.

Thus, this order should have established an investigation under section 206 of the Federal Power Act into the appropriateness of effective price mitigation until the longer term solutions are in place and the markets operate normally. This investigation would assess, through comments, whether conditions in the western interconnection are preventing competitive market operation, how long those conditions are expected to last, and what the Commission can do to provide immediate price mitigation to ensure that prices are just and reasonable. We would also inquire about how any mitigation measures should be applied and how long they should last. A specific sunset provision is important to maintain investor confidence that price mitigation is temporary and imposed only to deal with a poorly functioning market and to provide an incentive to ensure that the market problems are addressed expeditiously.

And finally, a section 206 investigation into wholesale electricity prices in the western interconnection would set a refund effective date 60 days hence so that the Commission can protect consumers if our investigation finds that prices are not just and reasonable.

I attach the utmost importance to initiating such an investigation. I dissent from this order for its failure to do so.

Having said that, I support many of the measures that today's order puts in place immediately, such as: extending and broadening temporary waivers of QF standards; facilitating market based rate authority for sales from back up and self generation at business locations; authorizing customers to “sell” load reduction at wholesale and at market based rates; facilitating wholesale contract changes to allow demand side management and facilitating demand side cost recovery in wholesale contracts. Many of these same actions were authorized by the Commission last year in our May 2000 reliability initiative. They were good ideas last year and they are good ideas now.

Beyond those measures, I have strong reservations about the proposed premium on equity returns for certain transmission and interconnection facilities. Some of these proposals could result in a 14.5% return on equity. There is no particular rationale for that level of return other than to simply throw money at the problem. Moreover, the Commission was very careful just a little over a year ago in Order No. 2000 to limit such incentive rate treatments to RTO participation. The premiums offered here are done so outside of the RTO context. I therefore must dissent from this order's proposal on equity premiums.

I also have concerns with the hydro provisions of this order. The Commission urges all WSCC hydropower licenses to examine their projects for the purpose of reporting possible efficiency modifications that could result in increased generation and to identify any environmental impacts that could occur if the efficiency changes are made. The primary focus of my concern relates to the notion that the Commission might urge licensees to unilaterally modify discretionary operations to increase electricity generation, without taking adequate responsibility for any environmental downside associated with such a decision. Healthy fisheries in California and the west are not a frill, but an integral part of the region's economy.

There is already great concern about these facilities. For example:

  • The Columbia River and most of its tributaries are draining an abnormal amount of rain, providing concern that there will not be nearly enough water to allow juvenile salmon to reach the ocean. Reservoirs across western Washington, most notably on the Cowlitz River, are down to some of the lowest levels since dams were constructed in the 1960's.
  • The 717 foot high Dworshak Dam which contains one of the most critical storage reservoir in the West, is a half-million acre feet short of water. The 54 mile reservoir is nearly 50 feet lower than normal. This facility is critical to the survival of the endangered chinook salmon. So far, almost 200,000 acre feet of water have been diverted from Dworshak.

For the above reasons, I will dissent in part to today's order.

Start Signature

William L. Massey,

Commissioner.

End Signature End Preamble

Footnotes

1.  For purposes of this order, we are concerned with what actions may affect electricity supply and demand in the United States portion of the Western Interconnection, which is the area encompassed within the United States portion of the Western Systems Coordinating Council (WSCC).

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2.  We recognize that the States are also working on these issues, as exemplified by the Western Governors' Action Plan, and this Order is intended to complement what the states are doing. See Western Governors' Association website at http://www.westgov.org/​wieb/​power/​index.htm.

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3.  San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,294 (2000), reh'g pending.

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4.  See San Diego Gas & Electric Company, et al., 94 FERC ¶ 61,085 (2001)(Commission found that Cal PX was violating the December 15 Order, and if unremedied, would cost consumers substantial amounts of money and exacerbate the dysfunctions in the market).

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5.  Moreover, other Western states, particularly those in the Pacific Northwest, are also projected to have supply problems this summer, depending on rainfall and summer temperatures.

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6.  San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,121 (2000), reh'g pending.

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7.  Of course, we expect transmission providers to make maximum use of existing facilities. We remind transmission providers of their obligation to keep their Available Transmission Capacity (ATC) figures current, including updating Capacity Benefit Margin and Transmission Reliability Margin. Accurate ATC is crucial to facilitating power sale transactions that can relieve stresses on electric systems.

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8.  See Southern California Edison Company, Opinion No. 445, 92 FERC ¶ 61,070 (2000).

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9.  San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,238 (2000) (December 8 Order).

10.  San Diego Gas & Electric Company, et al., 93 FERC ¶ 61,294 (2000)

11.  In a letter to the Chairman of the Commission dated February 8, 2001, Governor Gray Davis of California requested that these waivers be extended until October 15, 2001, and the Secretary of Energy endorsed this request in a letter to the Chairman dated March 5, 2001.

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12.  18 CFR 292.205(c) (2000); see also 16 U.S.C. 825h (1994) (general authority to waive regulations as the Commission “may find necessary or appropriate”).

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14.  18 CFR 292.204(b)(2) (2000).

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15.  We have in fact approved a tariff under which the owners of such generation could sell electricity to a power marketer. InPower Marketing Corporation, 90 FERC ¶ 61,239 (2000) (InPower).

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16.  We note that while entities become “public utilities” subject to the Federal Power Act when they commerce the sale of electric energy at wholesale in interstate commerce, they cease to the public utilities when such sales cease (assuming they engage in no other activities that would make them public utilities) without further Commission action. See Century Power Corporation, 72 FERC ¶ 61,045 at 61,279 (1995).

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17.  See, e.g., InPower, 90 FERC at 62,105; Reliant Energy, Inc., et al., 91 FERC ¶ 61,073 at Appendix B (2000). The Commission has generally waived for such sellers the following parts of its regulations in 18 CFR: most of Subparts B and C of Part 35 (documentation), Part 41 (accounting verification), Part 101 (prescribed Uniform System of Accounts), and Part 141 (annual reports). In addition, where requirements are statutory, the Commission has allowed such sellers to make shortened filings to satisfy Part 33 (disposition of facilities) and Part 45 (interlocking positions), and has granted blanket authorizations for issuances of securities (Part 34).

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18.  Although we are asking all wholesale purchasers who seek to take advantage of these special procedures to file these reports, it is not our intent to assert jurisdiction over any wholesale purchaser who is not otherwise subject to our jurisdiction, and the submission of such reports will not alter a purchaser's jurisdictional status. Further, to the extent these waivers and authorizations include sales by on-site generators into energy markets administered by an independent system operator (ISO) or power exchange, the ISO or power exchange in that case may file the required reports with the Commission.

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19.  These streamlined procedures are similar to those placed into effect last summer. See Notice of Interim Procedures to Support Industry Reliability Efforts and Request for Comments, 91 FERC 61,189 (2000). They are offered as an option. Any public utility seller may also follow standard filing requirements if desired.

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20.  The waivers and authorizations granted here apply only to sales from on-site generators used primarily for back-up or self generation, and thus would apply up to the amount of capacity and related energy available from such units. The waivers and pre-granted authorizations do not permit an on-site generator that purchases power to resell its purchased power at wholesale. However, assuming such a resale is not contrary to the on-site generator's retail authorizations or purchased power contract, and is not otherwise encompassed within a DSM program, a rate schedule for the sale could be filed with us. In such case, the Commission will be receptive to granting waivers and authorizations consistent with these where there is customer consent.

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21.  We note that the ISO instituted a market-based wholesale demand responsiveness program on a four-month trial basis during the summer of 2000. Under this program, the ISO paid participants a monthly “capacity” payment in return for the ISO's ability to curtail these loads. Initial participation in the ISO's trial program reached 180 MW.

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22.  December 15 Order, 93 FERC at 62,016-17.

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23.  This paragraph also applies to revisions to contracts to permit a wholesale customer's participation in any utility DSM programs, including those of an ISO or power exchange.

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24.  See, e.g., Wisconsin Electric Power Company, Docket No. ER99-2180-000.

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25.  Regional Transmission Organizations, 65 FR 809 (January 6, 2000), FERC Stats. & Regs. ¶31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (March 8, 2000), FERC Stats. & Regs. ¶31,092 (2000), petitions for review pending sub nom., Public Utility District No. 1 of Snohomish County, Washington v. FERC, Nos. 00-1174, et al. (D.C. Cir.).

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26.  This represents almost 119,000 Mcf/d of capacity. See Questar Southern Trails Pipeline Company, 92 FERC ¶61,110 (2000); Tuscarora Gas Transmission Company, 93 FERC ¶62,102 (2000); Northwest Pipeline Corporation, 94 FERC ¶61,101 (2001).

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27.  There are eight pending pipeline proposals that represent 2.3 Bcf/d of new capacity for the West, including the Rocky Mountain region. They are: North Baja Pipeline Company, LLC, Docket Nos. CP01-22-000 et al.; Questar Pipeline Company, Docket No. CP00-68-000; Kern River Gas Transmission Company, Docket No. CP01-31-000; Colorado Interstate Gas Company, Docket No. CP00-452-000; Colorado Interstate Gas Company, Docket No. CP01-45-000; Wyoming Interstate Company, Ltd., Docket No. CP00-471-000; Northwest Pipeline Corp., Docket No. CP01-49-000; and El Paso Natural Gas Company, Docket No. CP01-12-000. In addition, El Paso Natural Gas Company is proposing to acquire and convert to gas use a 785 mile crude oil pipeline extending from Arizona to California, which would replace existing capacity.

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28.  In Northwest Pipeline Corporation, Docket No. CP01-62-000 (February 7, 2001) the Commission approved a proposal by Northwest to use existing portable compressors at three compressor stations to relieve capacity constraints on its system, which were forcing imposition of Operational Flow Orders and the purchase by shippers of more expensive gas supplies.

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29.  In addition, oil pipelines rely upon electricity for pumping, and to the extent pumping is affected by electric curtailments, oil products may not get delivered to generators that rely on such products. We request any comments as to whether this is a serious concern.

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30.  See Western Governors Association, “Suggested Action Plan to Meet the Western Electricity Crisis and Help Build the Foundation for a National Energy Policy” (March 2001). A copy of this document has been filed in this docket.

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1.  92 FERC ¶ 61,065 (2000), and 92 FERC ¶ 61,073 (2000).

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[FR Doc. 01-6955 Filed 3-20-01; 8:45 am]

BILLING CODE 6717-01-M