# Joint Appendix — American Paper Institute, Inc. v. American Elec. Power Service Corp. > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385009_0376%3A03 ## Record - **Collection:** Supreme Court brief - **Document type:** Joint Appendix - **Published:** January 1, 1983 - **Citation:** 461 U.S. 402 ## Text ON WRIT OF CERTIORARI TO THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT JOINT APPENDIX EDWARD BERLIN, Swidler, Berlin * Strelow, Chartered arragut Square Washington, D.C. 20006 (£02) 342-5500 Counsel of Record for Respondent Electric Utilities TABLE OF CONTENTS List of relevant docket entries at the court of ap- Order of the court of appeals granting leave to inter- vene to American Paper Institute, Elizabethtown Gas and Brooklyn Union, filed August 21, 1980 .. Order of the court of appeals granting leave to inter- vene to Occidental Geothermal, filed March 21, 1 ³˙·¹1¹ cedbkbdndes cabbaboneddbusadcecces List of relevant docket entries at the Federal Ener- gy Regulatory Commission, Docket No. eee sse Staff Paper Discussing Commission Responsibilities to Establish Rules Regarding Rates and Exemp- tions for Qualifying Cogeneration Facilities Pur- suant to Section 210 of the Public Utility Regula- tory Policies Act of 1978 s Notice of Proposed Rulemaking Regarding Imple- mentation of Section 210 of the Public Utility Reg- ulatory Policies Act of 19788 Comments of Brooklyn Union Gas Company, filed EE ED ese senses sees sees Orders Allowing Certiorarr ri. (1) Page LIST OF RELEVANT DOCKET ENTRIES IN THE COURT OF APPEALS 1. Petition of American Electric Power Service Corp., Con- solidated Edison Company of New York, Inc., and Colo- rado Ute Electric Association, Inc., for review of Feder- al Energy Regulatory Commission Order Nos. 69 and 70. Filed July 14, 1980. 2. Order granting motions of American Paper Institute, Ine., Elizabethtown Gas Company and Brooklyn Union Gas Company, for leave to interevene. Entered August 21, 1980. This order is reproduced herein at 2. 3. Order granting motion of Occidential Geothermal, Inc. to intervene out of time. Entered March 25, 1981. This or- der is reproduced herein at 3. 4. Opinion of the Court of Appeals. Filed January 22, 1982. The opinion is reproduced in the Petitioner’s Appendix at B-1 to B-134. 5. Judgment of the Court of Appeals. Filed January 22, 1982. The judgment is reproduced i in the Petitioner’s Ap- pendix at B-200 to B-201. 6. Order and Memorandum of the Court of Appeals denying petitions for rehearing. Filed April 9, 1982. The order and memorandum is reproduced in the Petitioner’s Ap- pendix at B-202 to B-204. 7. Order of the Court of Appeals denying suggestions for rehearing en banc, and Memorandum of dissenting judg- es. Filed April 9, 1982. The order and memorandum is reproduced in the Appendix at B-205 to B-208. 2 UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT SEPTEMBER TERM, 1979 No. 80-1789 Filed: August 21, 1980 AMERICAN ELECTRIC POWER SERVICE CORPORATION, ET AL., PETITIONERS v. FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT AND CONSOLIDATED CASE NO. 80-1531 ORDER On consideration of the motions of (1) Elizabethtown Gas Company (2) The American Paper Institute, Inc. (“API”) and (3) The Brooklyn Union Gas Company (“Movant”) for leave to intervene in No. 80-1789, it is ORDERED that the aforesaid motions for leave to inter- vene are granted. Counsel for the aforesaid intervenors may participate in oral argument only to the extent allowable under Rule 12 of the General Rules of this Court. In order to provide for maximum utilization of the provi- sions of Rule 28(i) of the Federal Rules of Appellate Proce- dure, the time for filing the brief(s) of the intervenors is ex- tended until fifteen (15) days after the briefs are filed by the principal party whose position they support. For the purposes of Rule 31(a), the time for filing the next brief will run from that date. For the Court GEORGE A. FISHER, CLERK By: /S/ DANIEL M. CATHEY First Deputy Clerk 3 UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT SEPTEMBER TERM, 1980 No. 80-1789 Filed: March 25, 1981 AMERICAN ELECTRIC POWER SERVICE CORPORATION, ET AL., PETITIONERS *. FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT ELIZABETHTOWN GAS COMPANY, AMERICAN PAPER INSTITUTE, INC. BROOKLYN UNION GAS Co., INTERVENORS ORDER The Clerk is directed to file the motion of Occidental Geothe mal, Inc. , to intervene out of time, on consideration thereof, and it appearing that the motion is unopposed and that the movant will comply with the briefing schedule set in this case, it is ORDERED that the aforesaid motion for leave to inter- vene is granted. Counsel for the aforesaid intervenor may participate in oral argument only to the extent allowable under Rule 12 of the General Rules of this Court. For The Court | GEORGE A. FISHER, CLERK By: /S / DANIEL M. CATHEY First Deputy Clerk 4 LIST OF RELEVANT DOCKET ENTRIES AT THE FEDERAL ENERGY REGULATORY COMMISSION Date June 26 July 23 Sept. 28 Oct. 23 Jan. 30 (FERC Docket No. RM 79-55) 1979 Staff Paper (44 F.R. 38863), discussing Commission Re- sponsibilities to establish rules regarding rates and exemp- tions for qualifying cogeneration and small power produc- tion facilities pursuant to Section 210 of the Public Utility Regulatory Policies Act of 1978. Notice of Regional Hearings (44 F. R. 44177): 7/23/79—Room 5048, California State Building 350 McAllister Street San Francisco, California 7/27/79—(Room to be designated) Everett McKinley Dirksen, Building 219 South Dearborn Chicago, Illinois 7/30/79—F ederal Energy Regulatory Commission, Hearing Room A 825 North Capitol Street Washington, D.C. 20426 8/1/79—-Comments Due Notice (44 F.R. 57107), setting public hearing to be held on the following dates in the designated cities: 10/17/79—New Orleans, Louisiana 10/24/79— Washington, D.C. 10/26/79— Boston, Massachusetts 10/17/79— Requests to participate to be filed Notice of Proposed Rulemaking (44 F. R. 61190) issued re- garding the implementation of Section 210 of the Public Utility Regulatory Policies Act of 1978. Notice issued (44 F. R. 61977), setting public hearings to be held on the following dates in the designated cities: 11/19/79—Seattle, Washington, 11/28/79—New York, New York 11/30/79— Denver, Colorado 12/3/79— Washington, D.C. 11/15/79— Requests to participate 1980 Notice issued (45 F. R. 7819), of meeting with State Regu- latory Commissioners on Staff Draft of The Final Rule. Feb. 5 Feb. 19 Mar. 31 5 2/4/80— Meeting from 2:00 to 5:00 p.m. in Room 9306, 825 North Capitol Street Notice issued (45 F. R. 8665), of meeting with Representa- tives of The Electric Utility Industry on Staff Draft of The Final Rule. 2/8/80— Meeting to be held from 9:00 to 12:00, in Room 2005 of FERC, 825 North Capitol Street. Order No. 69 and Final Rule issued (45 F.R. 12214), re- garding the Implementation of Section 210 of the Public Utility Regulatory Policies Act. Notice (45 F. R. 23661) of Finding of No Significant impact and notice of intent to prepare environmental impact state- ment issued. Order issued (45 F. R. 38958) granting in part and denying in part rehearing of Order Nos. 69 and 70, and amending regulations. Notice issued (45 F. R. 38040) setting conference as listed below concerning state implementation of small power pro- duction and cogeneration facilities: 6/17/80— Ramada Inn Airport at 8:30 a.m. to 5:30 p.m. Logan International Airport 6/20/80— Ramada Inn Airport at 8:30 a.m. to 5:30 p.m. Atlanta, Georgia 6/23/80—Holiday Inn Airport at 8:30 a.m. to 5:30 p.m. Boise, Idaho 6/25/80— Rodeway Inn (at Airport) at 8:30 a.m. to 5:30 p.m. Minneapolis/St. Paul, Minnesota 6/27/80—Holiday Inn Airport at 8:30 a.m. to 5:30 p.m. St. Louis, Missouri FEDERAL REGISTER, Vol. 44, No. 129 Tuesday, July 3, 1979 PROPOSED RULES (18 CFR Part 292 [Docket No. RM79-55] Staff Paper Discussing Commission Responsibilities To Establish Rules Regarding Rates and Exemptions for Qualifying Cogeneration and Small Power Production Facilities Pursuant to Section 210 of the Public Utility Regulatory Policies Act of 1978 Agency: Federal Energy Regulatory Commission. ACTION: Staff paper issued, by direction of the Commis- sion, for comment. SUMMARY: This paper discusses the Commission’s re- sponsibilities to issue final rules pursuant to section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) relating to the rates at which power should be exchanged between qualifying cogeneration and small power produc- tion facilities and eletric utilities and the criteria under which certain qualifying facilities should be exempt from certain State and federal regulations. DATE: Comments are due by August 1, 1979. ADDRESS: All comments to: Secretary, Federal Energy Regulatory Commission, 825 North Capitol Street, N.E., Washington, D.C. 20426 (Reference Docket No. RM79-55). FOR FURTHER INFORMATION CONTACT: Adam Wenner, Office of the General Counsel, Federal En- ergy Regulatory Commission, 825 North Capitol Street NE., Washington, D.C. 20426 (202) 275-0422. Robert Cackowski, Office of Electric Power Regulation, Federal Energy Regulatory Commission, 825 North Cap- itol Street, NE., Washington, D.C. 20426 (202) 275-4779. June 26, 1979. Memorandum to: The Commission. From: John B. O Sullivan, Chief Advisory Counsel; Robert E. Cackowski, Deputy Director, OEPR. Subject: Section 210 of the Public Utility Regulatory Poli- cies Act of 1978, Concerning Cogeneration and Small Power Production Facilities. This memorandum is intended to serve as a discussion pa- per on Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA). The memorandum will describe this section of the law, our preliminary view as to how the law might actually work, and some problems that might devel- op in implementation. Introduction Under the Federal Power Act (FPA), sales from cogen- erators and small power producers to a public utility (as de fined in Part II of the FPA) would, so long as the electrici- ty might make its way into the bulk power transmission grid, make the cogenerator or small power producer itself a public utility. In other words, by virtue of its sale for resale in interstate commerce, the cogenerato or small power producer would itself become a public utility under Part II of the Power Act. Prior to the enactment of PURPA, the FERC was not authorized to abstain, in whole or in part, from exercising its jurisdiction over such cogenerator- public utilities and small power producer-public utilities. The prospect of plenary regulation unquestionably acted as a powerful disincentive to the generation and sale of sur- plus power by such facilities, particularly where the owner was an industrial concern unfamiliar with the arcane intri- cacies of utility regulation. It should be noted that sales of supplemental or back-up power to such cogenerators and small power preducers by the local public utility would in most instances be a retail sale regulated by the State. In Sections 201 and 210 of PURPA, Congress has grap- pled with both the split jurisdiction and the disincentive to certain desirable kinds of electric generation imposed by the rigid jurisdictional provisions of the FPA, as well as with allegations that some utilities were not dealing in good faith with certain existing or proposed cogenerators and small power producers. The PURPA scheme, though cer- tainly novel in the context of traditional utility regulation and probably complex to administer, is a logical approach to solving the problems with which Congress was concerned. Section 201 of PURPA generally defines a “qualifying small power production facility,” “qualifying small power producer,” “qualifying cogeneration facility,” and “quali- fying cogenerator.” The Commission is to establish by rule the detailed criteria for qualifying facilities of both types. Generally, a qualifying small power production facility (SPPF) can only use biomass, waste, renewable resources (including hydro from existing dams), or a combination thereof, as a primary energy source; and, together with other facilities at the same site, cannot have a capacity greater than 80 megawatts. A cogeneration facility is de fined as a facility which produces both electricity and steam or some other useful forra of energy, such as heat. There is no size limit for qualifying cogeneration facilities. A quali- fying facility of either type must be “owned by a person not primarily engaged in the generation or sale of electric pow- er (other than electric power solely from cogeneration facil- ities or small power production facilities). Having delineated by Section 201 and the Commission rules promulgated thereunder the class with which it was dealing, the Congress provided certain substantial benefits of qualification in Section 210. Broadly stated, these bene- fits are the following: ' However, a utility or a number or utilities may participate in the ownership of a facility; and nothing in the statute bars a utilit, from operating a qualifying facility. In fact, a utility operating such a facili- ty which it did not own would become a “qualifying cogenerator” or “qualifying small power producer.” (1) Electric utilities (defined as any person, State agency or Federal agency which sells electric energy)“ can be compelled to buy power from qualifying facilities. The price applied to such required purchases must be just and rea- sonable to the customers of the purchasing utility and in the public interest. The Commission may not prescribe a price for such sales that “exceeds the incremental cost to the electric utility of alternative electric energy.” The price shall not discriminate against the selling qualifying cogen- erator or small power producer. (2) Utilities can be compelled to sell to qualifying facili- ties. The price applied to such required sales shall be just and reasonable and in the public interest and shall not dis- criminate against the qualifying cogenerator or small power producer. (3) Qualifying small power production facilities whose size does not exceed 30 megawatts of capacity and all quali- fying cogeneration facilities may be exempted in whole or in part by Commission rule from the Federal Power Act, from the Public Utility Holding Company Act, and from State laws and regulations respecting the financial or or- ganization regulation of public utilities, if the Commission determines such exemption is necessary to encourage co- generation and small power production. Rules embodying these principles are to be issued by the Commission within one year after enactment; viz, by No- vember 8, 1979. The law provides that the State regulatory authorities and nonregulated utilities are to implement the Commission’s rules within a year after they are prescribed. As this bare-bones description of the statute may or may not make apparent, there is the potential, if not a require- ment, for a fundamental reordering of the traditional dual 2 The definition of electric utility applicable to Section 210 is that which appears in Title I of PURPA (and which includes the Federal power marketing agencies), not the Title II definition (which does not). The Title II definition (from PURPA § 201) has become a part of the Federal Power Act (specifically, § 3(22)), and thus applies to the parts of PURPA which amend the Power Act. Section 3(4) of PURPA estab- lishes the definition to be applied to those parts of PURPA which, like Section 210, are not made a part of the Federal Power Act. 10 regulatory scheme as it applies to certain cogenerators and small power producers.* Whereas before the FERC had ju- risdiction over sales from such power producers for resale in interstate commerce, while the states regulated retail sales, PURPA provides for FERC rules governing both transactions. And the states, which have not had jurisdic- tion over sales for resale in interstate commerce, will in all likelihood carry out the day-to-day regulation of such sales where they involve qualifying facilities (Fs) in addition to continuing to regulate all retail sales, including sales to QFs. However, the regulation of transactions involving s may well be conducted under the state regulations im- plementing the FERC’s rules promulgated pursuant to Sec- tion 210, rather than under State laws. In other words, the requirement that the States and nonregulated utilities im- plement the FERC’s rules, together with the FERC’s au- thority to exempt s from some or all of Parts II and III of the FPA and from State law could (and almost certainly will) result in the delegation-by-exemption to the States of both old and new FERC regulatory responsibilities. The second major departure from or reordering of tradi- tional utility regulation inherent in the Section 210 scheme is a consequence of the Congress’s intention to avoid the treatment of qualifying cogenerators and small power pro- ducers as utilities, where such treatment is a disincentive to these kinds of generation. Traditional regulation has, naturally, focused on the seller. For the most part, regula- tors regulate the public utility, not its customers. There is plentiful precedent for a requirement to sell (Sections 202(b) and (e) of the FPA, virtually all State laws concern- ing service to retail customer), but almost none for re- quired purchases of the sort provided for in Section 210. Similarly, under conventional regulation, the seller’s rates are subject to regulatory approval, the test of the reasona- bleness of which is the seller’s costs. Here, because of the effort to relieve some generators of the burdens of regula- Except where a precise point of statutory construction is being dis- cussed, we will use the terms “cogenerator” and “small power produc- er”, interchangeably with, respectively. “cogeneration facility” and “small power production facility.” 11 tion. Congress has established a scheme in which the pri- mary reference point for determining the price for a sale from a QF to a utility is not the seller’s cost but the buyer’s avoided cost. Indeed, the Congress has specifically in- structed FERC that s are not to be subjected to the same scrutiny and requirements for organization and re- porting as regular utilities; and the authority to grant ex- emptions is the device which Congress has given the Com- mission not only to avoid such regulation on its own part, but also to ensure that once the Federal preemption of such regulation is removed, the States do not begin to regulate s as utilities. All this is not to say that there is a lack of precedent for the Commission, State regulators, and nonregulated utili- ties to look to in implementing Section 210 of PURPA. Many utilities have experience with their own cogeneration (primarily those that provide district heat steam service.) With regard to the sale from a utility to a qualifying facili- ty, the primary model is conventional State-regulated retail sales, though in some instances partial requirements or in- terchange wholesale rates provide a better basis of compar- ison. With regard to the sale from a qualifying facility to an electric utility, wholesale rates probably provide the best analogy in most cases, particularly where a relationship be- tween a utility and a number of qualifying facilities begins to resemble a power pool. Useful information may also be gleaned from the not-uncommon arrangement whereby a utility purchases power from an industrial cogenerator or self-generator. A number of States have already begun work on rules concerning cogenerators and a few are quite far along this road, and this also can provide substantial guidance. Nonetheless, it is fair to say that in many instances the transactions between utilities and those who will qualify under Section 201 have in the past fallen into a gap between the FPC/FERC and State regulators. It is certain that the terms under which these transactions take place vary enor- mously from utility to utility and region to region. In the following more detailed discussion, we will not attempt to provide in all instances a single correct or even preferred 12 approach to implementation. Because of regional differ- ences in circumstances, the enormous range of characteris- tics as to both loads and power production likely to be exhibited by various qualifying facilities, and simple uncer- tainty as to what the law means or what the best approach to a problem is, we will often merely list some apparent alternatives. By this we do not mean to imply that the Commission will in every case ultimately be faced with making a choice of a single approach from among a number of alternatives. It is quite likely that the Commission will want Lo leave the States and the nonregulated utilities flex- ibility for experimentation and accommodation of special circumstances on a number of these matters. With respect to the nonregulated utilities, consideration will be given as to the necessity of a separate set of rules from that applicable to the State commissions due to the fact that the nonregulated electric utility will be both the entity responsible for implementing the Commission’s rules and the utility directly dealing with the cogenerator or small power producer. Exemptions _ Section 210 directs the Commission within a year of en- actment to prescribe rules exempting small power produc- tion facilities with no more than 30 megawatts of capacity and all cogenerators from part or all of the Federal Power Act, from the Public Utility Holding Company Act, and from State laws and regulations respecting the rates or respecting the financial or organizational regulation of utili- ties, if the Commission determines such exemption is nec- essary to encourage cogeneration and small power produc- tion. Small power production facilities of greater than 30 megawatt capacity using biomass exclusively as a primary energy source may be exempted from the Holding Compa- ny Act and State laws, but not from the Federal Power Act.“ Under 210(e)(3), no QF can be exempted from Part I * Thus the Commission is not authorized to exempt small power pro- duction facilities of 30 to 80 megawatt capacity from any of these laws, with the exception of biomass users who still canot be exempted from the FPA. As a technical matter, this would leave in place two conflict- 13 of the Power Act, Sections 210,211 and 212 of the Power Act (added by Sections 202, 203 and 204 of PURPA, and having to do with interconnection and wheeling), and State iaws and regulations implementing the Commission’s rules promulgated pursuant to Section 210. I’ » clear from the Conference Report that Congress in- te the Commission to make liberal use of its exemption authority: The conferees wish to make clear that cogeneration is to be encouraged under this section and therefore the examination of the level of rates which should ap- ply to the purchase by the utility of the cogenerator’s or small power producer’s power should not be bur- dened by the same examination as ave utility rate ap- plications * * *. The conferees expect that the estab- lishment of utility type regulation over them would act as a significant disincentive to firms interested in co- generation and small power production. Although we have not conducted an exhaustive survey, there is good reason to believe that many if not most State laws provide for regulation of cogeneration and small power production facilities as utilities. These State laws have been rendered ineffective in most instances because of the FPA preemption of regulation of sales for resale in interstate commerce. Were the Commission to exempt s from FPA regulation, but not from State regulation, the State laws would then take effect, frustrating the intent of Congress that QFs not be subjected to same scrutiny and organiza- tional requirements as utilities. It would be difficult to maintain that the Federal preemption continued even after ing regulatory schemes covering this group: Section 210 pricing, and traditional Federal Power Act regulation of the QSPP who becomes a Part II public utility by virtue of a wholesale sale into interstate com- merce. The Conference Report resolves this for the most part by in- structing the Commission to use Section 210 pricing for this group. Left unresolved are two questions: (1) What will be the effect of State regulation on small power producers of greater than 30 megawatts who are making sales for resale but not into interstate commerce (such as in Alaska, Hawaii, Puerto Rico and most of Texas)? and (2) Should the Commission exempt biomass small power producers in these areas from State regulation, where the consequence is that they will not be regulated at all? 14 the Commission exempted s from the FPA (that is, that the area was deliberately left vacant, and that the States could not then occupy the area) if the Commission chose not to exercise its authority to exempt from State regulation. Therefore, it seems likely that in the great majority of cases where the Commission provides an exemption from the FPA it will also want to provide substantial exemptions from State law. Basically, there are two approaches that can be taken to the State law exemption. The first, which is both more pre- cise and more cumbersome, is to analyze the laws of each State and specify the exemptions to be provided citing sec- tions of State law and regulations. We do not recommend this approach, except possibly for the noncontiguous states and territories and contiguous areas not hooked into the in- terstate grid (primarily parts of Texas). The second ap- proach is to make a broad prescription exempting from any and all provisions of State law and regulations as would conflict with the State’s implementation of the Commis- sion’s rules under Section 210. This approach, while it may lead to some disputes which the Commission will have to become involved in, has the advantages of simplicity, ad- ministrative ease, and permanence (i.e., the language of the exemption would have to be changed every time a State changed its laws or regulations). While the proper course seems obvious with regard to Federal and State rate regulation and the requirements for filing voluminous reports concerning operation, cost and 5 Note that the Commission does not have the authority to exempt cogenerators from State regulation as a steam utility. This fact may have somewhat disparate consequences (assuming that some cogener- ators may be interested in selling steam), since some States do not reg- ulate steam sales, some do so only if the seller is already a utility, and some do so whether or not the seller is an electric utility. A quite different and somewhat anomalous situation involving pre- emption may arise if a State has by statute directed the State regula- tory authority not to regulate cogenerators. The most reasonable ap- proach to this situation would seem to be to treat the State law as consistent with Section 210 of PURPA, in that (as the Introduction points out) it is really the utility as buyer and seller that is regulated. 15 1 revenue data,“ the matter of exemption from provisions of the FPA concerning financing and related matters and from the Public Utility Holding Company Act is not nearly so clear. Pending consultation with the Staff of the Securities and Exchange Commission, we will not attempt an exhaust- ive analysis of this subject. However, as a rule of thumb it seems reasonable to provide that where a firm is subjected to more stringent regulation than other companies simply because it is engaged in electric utility business, those re- quirements should be eased through exemptions for QFs; but where a certain kind of regulation is applied to electric companies under the FPA or the Public Utility Holding Company Act, and applied in equal measure to non-utilities under other statutes enforced by the S. E. C., the argument for exemption is not nearly so strong. An example of the former, utility-only kind of provision is the requirement that a holding company show that its subsidiaries are or are capable of being operated on an integrated basis. In this case, we think, exemption warranted. By contrast, exemp- tion from certain security acquisition and interlocking di- rectorship provisions may not be warranted. As the Conference Report indicates, some participation by one or more utilities in the ownership of qualifying facili- ties may be permitted by the Commission’s Section 201 rules. However, an exemption granted to a facility under 210(e) would not serve to release a utility or holding compa- ny participating in some way in a QF’s ownership from any other unrelated obligations it may have under the law, since Section 210 permits the exemption of the QF, not of a parent (or grandparent). (In this context, we take this to mean that where a facility is granted an exemption, partici- pation in the ownership of the facility will not give rise to a particular legal obligation that would have otherwise at- tached). We interpret 210(e) as giving the Commission suf- ficient flexibility to grant an exemption such that a non- utility parent is relieved of certain obligations while a ® Though it is worth noting that ome exemptions here will affect the data provided to the Energy Information Administration, where EIA’s authority is derived from the Federal Power Act. 16 utility or holding company participating in the same project is not. Again, the test for an exemption is whether it is “necessary to encourage cogeneration and small power production.” Finally, it should be noted that the exemption of Fs from traditional utility-type regulation, as specifically dis- cussed in the Conference Report, may have the effect of making Fs eligible for a 20% energy investment tax cred- it. A recent change (March 1979) in Treasury Department regulations permits the exclusion from “public utility prop- erty” of property used in the business of the furnishing or sale of electric energy if the rates are not subject to regula- tion that fixes a rate of return on investment. Prior to the change, any rate regulation made property subject thereto (and involved in the furnishing or sale of electric energy) public utility property. Being thus excluded from public utility property, qualifying facilities have an opportunity to come within the definition of “alternative energy proper- ty,” and thus qualify for the 20% ITC. In fact, it may well be that even small power production facilities too large to be exempted may be eligible for the higher tax credit, due to the Conference Report’s ine ic- tion to set the prices for sales by these SPPFs to utiaties in accordance with the requirements of” Section 210 rather than by “utility-type regulation.” Interconnection Section 210 requires that utilities buy from and sell to s. It does not, however, explicitly provide authority to the Commission to order any interconnection necessary to effect the required transaction. The question thus arises as to whether there is inherent in section 210 of PURPA the authority to order such interconnections, or whether Fs must use Sections 210 and 212 of the FPA (added by Sec- tions 202 and 24 of PURPA) to gain interconnection. Perhaps the strongest argument against the finding that there is an interconnection authority within the cogenera- tion section is that the interconnection section itself explic- itly lists qualifying cogenerators and small power producers as among those who are eligible to make an application. (By 17 contrast, the next section, dealing with wheeling, does not confer eligibility on Fs). Moreover, the requirement un- der Sections 210 and 212 of the FPA that the party seeking interconnection must show himself to be ready, willing and able to pay the resulting costs, and the companion criterion that the interconnection order not be issued if it would re- sult in a reasonably ascertainable uncompensated economic loss for any electric utility, might be seen as consistent with the statement in the Conference Report that the co- generation section was not to be applied so as to force a utility’s customers to subsidize a qualifying facility. Although this argument is respectable, we think it the better view that the requirement to interconnect is sub- sumed within the requirement to buy and sell. To hold otherwise would mean that Congress intended to have qual- ifying facilities go through an extended and expensive pro- ceeding simply to gain interconnection, contrary to the en- tire thrust of Sections 201 and 210. These sections evince the clear Congressional intent to encourage development of these desirable forms of genera- tion, and to have the commercial development of these fa- cilities proceed expeditiously. In other words, Congress has already made the judgment that these kinds of facilities serve one of the purposes of the Act as set out in Section 101, viz, “the optimization of the efficiency of use of facili- ties and resources by electric utilities”, and it would be both redundant and unduly burdensome to have the spon- sors of individual facilities show in an evidentiary hearing (FPA § 210(b)(2)) that their project in particular would serve this end (or one of the other related goals established as criteria for an interconnection order in § 210(c)(2)). Af- ter all, the purpose of an interconnection application, whether under Section 202 or 210 of the FPA, is to secure service, whether emergency or otherwise; and Section 210 of PURPA establishes the entitlement of a QF to service from the interconnected utility. In effect, the proponents of the view that a QF must apply under Sections 210 and 212 of the FPA have the burden of showing that Congress in- tended interconnection and the entitlement to buy and sell be denied to a QF which is unable to make the showings re- 18 quired by those sections even though a previously-intercon- nected customer installing qualifying facilities would not have to do so. This is not to say that all of the protections that Congress has given the target of an interconnection application in Sections 210 and 212 of the FPA are necessarily absent from Section 210 of PURPA. The Conference Report on Section 210 states that customers of utilities are not to be compelled to subsidize Fs, and this principle would seem to bear on the question of who pays the costs of intercon- nection as well as on the per-unit price to be paid for ener- gy. On the other hand, the conference Report includes a prescription against “unreasonable rate structure impedi- ments, such as unreasonable hook up charges.” (emphasis added) This provides another argument in favor of reading Section 210 as including interconnection authority, since the elaborate cost determination required under Sections 210 and 212 of the FPA is redunant if the costs of intercon- nection are viewed simply as a feature of the rate structure with the charge therefor based on the cost of the utility. Reliability Section 210(a) states that the rules requiring utilities to buy from and sell to s “shall include provisions respect- ing minimum reliability of [Fs] (including reliability of such facilities during emergencies) and rules respecting re- liability of electric energy service to be available to such fa- cilities from electric utilities during emergencies.” This statutory language raises the question of whether the Commission must prescribe minimum reliability re- quirements for qualifying facilities selling to utilities. Section 201 specifically mentions reliability as one of the factors the Commission may take into account in estab- lishing the criteria for qualifying small power production fa- cilities. (It is not mentioned in the parallel language con- cerning co-generators.) We read Section 201 as permitting but not requiring the Commission to establish a minimum standard for the reliability of small power producers. Whether one agrees with this interpretation or believes that the Commission must establish such a threshold, the 19 question remains as to why the Congress included provi- sions concerning reliability in Section 210 for both kinds of facilities after having mentioned it in Section 201 as to one kind but not the other. Of course, the degree of reliability and/or availability can and should be reflected in the price for electric service, whether a utility or a QF is the seller. Putting a price tag on a particular degree of reliability is practically an every- day exercise for utilities and regulatory agencies. Put an- other way, then, the question is whether the Congress in- tended the Commission to establish rules on QF reliability under Section 210 that went beyond a requirement that dif- ferences in reliability be fully reflected in prices. The Congress evinced a clear concern that utility custom- ers not be required by the Commission’s Section 210 rules to subsidize Fs. The 210(a) language concerning reliability might well have been intended to prevent indirect subsidies resulting either from frivolous or otherwise uneconomical interconnections (with the costs borne by the utility’s cus- tomers) or from a diminution in the quality of service rend- ered by a utility due to an interconnected facility’s disrup- tion of a utility’s operations. Elsewhere in this memorandum we have recommended that the incremental costs of interconnection or reinforce- ment of a utility’s distribution and transmission facilities (i.e., those costs which the utility would not have incurred in securing the same power from an alternative source, or in providing service to the qualifying facility if the facility did not have its own generation) should be borne by the QF. So long as facilities can be devised which are sufficient to protect the utility from disruption of its operations by a QF —and our present understanding is that such protective devices can always be provided—and the QF rather than the utility bears the costs of these facilities, then no such indirect subsidy would occur. Our analysis thus leads us to the conclusion.that every in- cidence of a QF’s reliability (or unreliability) can be ac- counted for through prices. If this conclusion withstands the test of public comment, we would recommend to the Commission that it establish no minimum reliability stand- ard pursuant to Section 210(a), but that it make full provi- sion for the consequences of varying degrees of reliability in the rules on pricing. It is reasonable to expect many different kinds jof facili- ties to be covered by and become involved with Section 210, ranging from large, self-sufficient and previously-isolated industrial generators to small, experimental and somewhat exotic facilities. The reliability that these different kinds of s will need from utilities and will be able to offer utilities will run the gamut. The needed services may vary from something comparable to a typical firm retail sale to more sophisticated pooling and interconnection arrangements. Similarly the service offered by QFs to electric utilities will range from dump or interruptible energy to firm power sales, i e., a reliable substitute for capacity that would oth- erwise be installed by the utility. It is difficult, if not impossible, to predict what kinds of facilities will present themselves to any given utility. Thus it appears that the approach that would best satisfy the statutory mandate to encourage cogeneration and certain types of small power production is to require all electric utilities to offer to buy and sell services providing a com- plete range of reliability,“ with the proviso that in each in- stance the price will have to be calculated so as to satisfy the other provisions of section 210, including the principle that utility customers not be compelled to subsidize QFs. This requirement that electric utilities offer a complete menu of services (at appropriate prices) should not be too great a hardship, at least for public utilities, since between their wholesale and retail rate schedules most now offer a broad range of services, including firm all requirements, standby, interruptible and emergency services (though many do not offer what may be the closest parallel in many instances, partial requirements service). We do not mean to imply by this that qualifying facilities could rely on this requirement to secure a higher degree of reliability that firm, full requirements customers, or secure for themselves a higher priority than other customers with similar end- uses under a short- or long-term emergency load-shedding plan. 21 With regard to emergency sales from s to utilities, we would note that cogenerators and small power can be the subject of an order under Section 202(c) of the FPA to provide energy if the Economic Regulatory Admin- istration determines that an emergency exists. Absent the declaration of a 202(c) emergency, we would recommend leaving the terms of emergency availability to the negotia- tions of the parties, subject only the rule recommended in the preceding paragraphs. Sales from Utilities to Qualifying Facilities Section 210(c) of PURPA provides that: The rules prescribed under Subsection (a) [which re- quires, inter alia, that utilities sell to Fs] shall insure that in requiring any electric utility to offer to sell electric energy to any qualifying cogeneration facility or qualifying small power production facility, the rates for such sale— (1) shall be just and reasonable and in the public interest, and (2) shall not discriminate against the qualifying cogener- ators or qualifying small power producers. XR R K X * This statutory language is similar to the language con- tained in Sections 205 and 206 of the FPA and is probably similar to many of the State statutes with respect to utility regulation. Such language thus permits traditional rate- making concepts with respect to the sales to QFs. In most instances, it would appear appropriate for the proposed rules to require the States to apply their standard ratemaking concepts in establishing rates for the QFs to the extent possible, even where there is a significant differ- ence between FERC’s approach and that of a state. That is, in most instances the test as to whether a QF is being dis- criminated against as a utility customer will be made by comparing the QF to other retail customers of the utility. For example, although California might choose to exempt qualifying facilities from having to pay a share of the subsi- dy for lifeline rates required of other industrial customers, there does not seem to be a valid argument that the failure to exempt s is discriminatory, since the Ms would sim- ply be treated like others in the class to which they would belong if they did not have their own generation. Similarly, there seems no reason why any steps taken under Title I of PURPA with respect to such matters as time of day rates should not also apply to s. In determining the rates to Fs, one of the first issues likely to arise is whether all or some Fs should be served as a separate rate class or included among a more general class such as the industrial or large power customers. It would appear that latitude should be given in the rules to permit inclusion of Fs within a general rate class to the extent that the load characteristics permit. This may be the most practical approach where the number of potential Fs is relatively small and might not warrant the costs associ- ated with developing a separate rate class. Similarly, lati- tude should be given to permit classification as a separate rate class if the number of potential customers is large and/or the load characteristics are likely to impose substan- tially different costs on the system from the general rate class. These general problems of customer classification will of course become less important to the extent the states move to time-of-day rates. Two major problems arise in the area of customer class assignment due to a shortage of good data. First, a majori- ty of utilities do not have good load data even for their ma- jor retail customer classes, and in a number of states nei- ther the utilities nor their regulatory agencies set rates based upon a class cost of service calculation. (The load data problem will be resolved over the long haul for the larger electric utilities by Section 133 of PURPA, which re- quires the collection of cost and load information by custom- er class.) Second, even where utilities have good data for their existing major classes, estimates as to the service re- quirements of s, and thus the costs imposed on the utili- ty (determined to a considerable extent by the outages of the customer’s own generation and the type of standby service the customer wants), may not at first rise above the level of speculation. The second problem may be eased substantially over the short run if s and utilities can agree to contracts speci- fying the services the utility will be called on to provide. However, where the two parties cannot reach this kind of agreement (such as where a cogenerator is unsure of its own production and is not willing to contract for interrup- tible service from the utility for any part of its potential load), the problem remains. Whether or not a QF agrees to specific contractual levels of service, and whether a QF is assigned to an existing cus- tomer class, has a custom-designed individual rate, or is placed in a special class (or one among several special classes) for s, the first problern does not seem suscepti- ble of precise solution over the short term. It would seem difficult to declare with any confidence that rates for a par- ticular customer or class of customers is just and reason- able if there is no approved way of determining the custom- er’s cost responsibility; and it would seem to be impossible to determine with any precision whether or not a proposed rate were discriminatroy when one does not know the cost of serving the class or classes whose rates the QF’s rates are to be compared to. Indeed, it may even be difficult to determine whether or not some or all QFs should be grouped with a particular class or subclass when little is known about the cost and load characteristics of the class. Since some cogenerators and small power producers may have operations similar to those of utilities with generating facilities, the rules should provide sufficient latitude to per- mit interconnection and coordination agreements or partial requirement agreements similar to those subject to this Commission’s jurisdiction. This would provide contractually specified operating criteria and would allow a full range of services including the sharing of mutual benefits of diversi- ty and coordination. In fact, wholesale rates may provide some makeshift basis for determining what retail rates are appropriate for M s where little is known about retail loads and costs by class. Where large numbers of existing customers are con- verting their operations from those of a full requirements customer to that of a cognerator or small power producer, such conversion may significantly alter total system loads and costs and almost certainly alter the outcome of a class cost allocation. To the extent that the conversion increases the total system costs from what they would otherwise be, or, more likely, leaves roughly the same fixed costs to be spread over fewer units sold, the rules should permit con- sideration of this fact by the states in determining the rates for such customers and the remaining customers on the sys- tem.“ This situation might become a significant factor in de- termining whether the rates are in tne “public interest” as required by Section 210(c). (The effect on system loads and costs is also an important consideration in determining the rate for power purchased by the utility from the cogener- ator or small power producer, as discussed later.]. One of the most often discussed problems of rates for cogenerators or small power producers is the charge for backup or standby service. Here, the question of what costs the customer(s) imposes on ‘the utility, and thus what the appropriate rate is, essentiallly turns on three factors: first, the reliability of customer’s generating equipment, or, put another way, the likelihood that the customer will be unable to supply part or all of his own electricity needs; second, the extent to which the customer will call on the utility to make up such a deficiency; and third, the degree of coincidence between such outages and the utility's peak demands. Cagenerators generally argue for lower backup charges based on the fact that they are unlikely to experi- ence outages all at the same time, whereas the utilities ar- gue for higher charges due to lack of ability to predict the time or duration of an outage since the operation of the fa- cilities is outside a utility control. In part, this argument comes down to prudent utility planning for meeting loads that are potentially volatile and are dependent in part on the maintenance practices of the nonutility operators. Where there is not a retail class of customers for backup service, with a rate based upon group outage probabilities, or perhaps even where there is such a class, latitude should be giwen in the rules to permit groups of qualifying cogen- ® We do not mean to imply that the entire shortfall, if there be any, should be imposed on Gs: rather, we merely suggest that it does not seem inappropriate for s to bear some share of the burden. 25 erators or small power producers to contractually “pool” their operations among themselves to minimize the poten- tial cost impact on the utilities. By first pooling among themselves, QFs might facilitate individual contractual dealings with utilties and reduce its attendant costs. Pooled s certainly could make a much stronger argument that probabilistic analysis should be used in determining the backup charges, and based on the coordination the analysis would show a lowered probability of coincident outages. u ch “pooling” might include arrangements such as coordinated maintenance or mutual spinning reserves.“ The pooled operations could also be coordinated with the utility further to minimize the potential cost impact of outages. Such pooling would entail some sacrifice of the s' flexi- bility in operations, but the resulting lower backup charges may provide a sufficient incentive. To the extent that oper- ations are not coordinated and individual QFs and the group of Fs as a whole impose greater capacity require- ments on the utility system, the costs of such backup serv- ice should be fully recovered. In the analysis of and negotiations over backup probabili- ties and responsibilities, recognition should be given to the fact that some cogenerators will not be able to continue part or all of their industrial operations if their steam (and thus electric) production facilities break duwn or are closed down. In other words, some cogenerators may not want or need backup for the part of their electric requirements re- lated to industrial processes that also require steam— when there is no steam, they shut down and go home. On a relat- ed matter, recognition should be given to a customer’s own backup or reserves in the form of redundant capacity. A customer having sufficiently reliable facilities of its own might consider contracting for backup service from the util- ity on an as-available basis {for the portion of its load that it is sure it can supply itself. * Although the latter would arguably reduce backup generating re- quirements on the utility's system it may not reduce transmission costs. One likely area of contention that arises in connection with interruptible and standby service is the recovery of the utility’s customer or facilities costs. There is likely to be somewhat less debate concerning the magnitude of these costs where the customer is a large industrial or commer- cial facility, since the design of facilities and determination of their cost is often arrived at on the basis of individual ne- ‘ gotiation now even where the customer does not have its own generation. [We will diseuss these interconnection costs in the next section.{ Where smaller customers are in- volved, however, the rate design for the class to which the customer is assigned may provide for the recovery of some customer costs through usage charges, and may also pro- vide for the recovery of some capacity costs through energy charges. In these situations, the utility is likely to as- sert—and with considerable merit—that minimum charges have to be increased so as to ensure the recovery of its fixed costs (and some expenses) from dedicated facilities when the customer does not buy enough energy in a given period to reimburse the utility under the conventional rate design. A minimum bill calculated to recover these costs would seem to be a reasonable approach to this matter, though a discrimination problem might arise if the QF is paying a fully compensatory minimum charge while sub- stantial numbers of customers in the class to which the QF would belong but for its own generation do not return their customer costs. The final question to be addressed in this section is whether the Commission should specify the kinds of inter- connection that should be made available to s as custom- ers of a utility. Specifically, the question is whether s in general should have an entitlement to operate in parallel with utilities (so that the same customer circuits can be served simultaneously by both customer- and utility-gener- ated electricity), or whether this should be left to the States or the parties (in which case some Fs may be forced to segregate circuits). In addition to the considerations of cost and possible in- terference with system operations, there are safety aspects which will require coordination and procedural safeguards. 27 For example, when certain lines are taken out of service in order to perform maintenance or repairs on such lines, ade- quate procedures must be in place to ensure that they are not energized by the other party prior to completion of ihe work. However, on the basis of preliminary discussion it appears that problems of operations, equipment protection and worker safety can all be solved, and that in the final analysis this question mostly concerns cost. Therefore, we recominend that operation in parallel be a required option, so long as the customer is willing to bear the costs of the fa- cilities necessary to protect workers and equipment. Sales from Qualitying Facilities to Utilities Section 210(b) of PURPA provides that the Commission's rules shall insure that in requiring any electric utility to of- fer to purchase electric energy from any qualifying cogen- eration facility or qualifying small power production facili- ty, the rates for such purchase— (1) Shall be just and reasonable to the electric con- sumers of the purchasing utility and in the public in- terest, and (2) Shall not discriminate against qualifying cogener- ators or qualifying small power producers. * XR eK * The statute provides that the rate for required purchases not exceed the ineremental cost of alternative eleetrie ener- gy, which is defined as the cost of energy which, but for the purchase, the utility would generate or purchase from an- other source. The rules may not authorize a QF to make a sale other than for resale, though State law may permit a QF to make such sales. Perhaps the most important question facing the Cpmmis- sion in the pricing area (but probably not the most difficult question) is whether Section 210 contemplates the payment of capacity charges to s under any conditions. Section 210 itself speaks only in terms of “electric energy.” While this term does not exclude the payment of capacity charges, it does not clearly include it either. For the most part, the Conference Report also uses the term “electric energy.” Even the example given in the Conference Report (in support of the point that the cheapest energy available at a given time does not necessarily fix the ceiling of the amount to be paid a QF, because the utility may not have intended to use that cheap (hydro) power at the time the sale took place) is cast in terms of energy costs and energy charges. There is, however, considerable language in both the statute and the Conference Report in support of the propo- sition that capacity payments are, at least in some circum- stances, not only legal but mandated. First, the “incremen- tal cost to the electric utility of alternative electric energy” would, where capacity is purchased or installed, include a capacity cost. If a cogenerator were offering energy of a like reliability for a similar term, the alternative cost would clearly not be limited to, for example, the energy compo- nent of the alternative rate where the alternative is a firm or unit purchase. Indeed, one can well argue that to pay the QF a price based only on displaced energy costs where an- other utility would receive a capacity payment as well for the same service is discriminatory in violation of the statute. The Conference Report addresses the calculation of the alternative cost standard at some length. The final para- graph of this section of the Report is the following: The conferees expect that the Commission, in judging whether the electric power supplied by the cogenerator or small power producer will replace future power which the utility would otherwise have to generate itself either through existing capacity or additions to capacity or pur- chase from other sources, will take into account the reliabil- ity of the power supplied by the cogenerator or small power producer by reason of any legally enforcible obligation of such cogenerator or small power producer to supply firm power to the utility. The references to “additions to capacity” and to obliga- tions “to supply firm power” (the rates for which, in our ex- perience, always include a capacity component) bring us to the conclusion that the better reading of Section 210 is that capacity payments to QFs can be required under certain circumstances; and that, indeed, a utility’s refusal to make 29 payments based in part on avoided capacity payments could be discriminatory. The paragraph from the Conference cited above also has a message for s, however; utilities make capacity pay- ments to each other where firm commitments to make and hold capacity available are involved. A cogenerator or small power producer which is unwilling or unable to make such a commitment and to achieve a high degree of reliability, is not enabling the purchasing utility to avoid the costs of con- struction or a capacity purchase, and thus these costs do not serve to increase the ceiling on the rates the QF can demand. In short, the statute provides an upper limit on the price for a capacity purchase (including an energy rate compo- nent) at the alternative capacity and energy costs avoided due to such purchase. Among other things, the duration of the purchase, the planning horizon of the utility and the ca- pacity and load situation of the utility will affect such alternative costs. Generation expansion models (which dis- count the future costs of alternatives to a common present value) may be used to quantify such costs once the magni- tude and duration of capacity purchases are known. The composition of such studies would vary depending on the answers to certain questions: Will utilities be required to pay now on a discounted basis for capacity not yet needed? Will capacity sales have priority over dump energy? How far into the future must utilities commit to buy, both as to initiation and duration of the sale? Interruptible (by the QF) energy sales can be priced a number of ways. Fopr example, a split-the-savings concept similar to economy energy purchases in existing inter- change agreements could be employed.“ Although econ- omy energy is normally priced on an hour-by-hour, trans- action-by-transaction basis, consideration should be given to a more general approach with lower administrative costs such as estimated monthly or annual savings. The differ- % This analogy may be of some assistance where a State's fuel ad- justment clause rules, like FERC’s, permit a complete pass-through to customers of the cost of economy purchases where the cost is lower than that of the displaced fuel. 30 ence between the cogenerator’s out-of-pocket cost and the utility’s out-of-pocket cost avoided as a result of the trans- action would be shared on an equitable basis between the QF and the utility. Rather than the typical equal split of the savings, latitude should be given to permit negotiations resulting in a greater proportion of the savings going to the cogenerator in order to encourage cogeneration as intended by the statute. S» long as the price is less than the alterna- tive cost to the u lity, the buying utility’s ratepayers bene- fit from such transactions, and the statute would seem to be satisfied.“ Such an approach may seem to depart from the Conferees’ directive not to scrutinize the costs of Fs as though they were utilities. However, this approach should not generally produce a substantial burden on the QF since in most cases the QF should have calculated its marginal energy cost to determine if it can afford to sell to a utility, particularly at times when the utility’s marginal running cost is low. In any case, the statute does not pro- hibit all inquiry into a QF’s costs, and this approach would not require a determination of a reasonable rate of return to the QF, which appears to be the conferees’ primary concern. Where a utility is a member of a centrally dispatched pool, the pool’s marginal running cost will probably be the appropriate measure of the ceiling for energy rates. Simi- '! The Conference Report states that a utility shall not be required to purchase energy from a QF at a rate which exceeds the lower of (1) the rate that is just and reasonable to the utility's customers and nondiscriminatory as to the QF and (2) the incremental cost of alter- nate electric energy. As stated above, we think that so long as the service being offered by a QF is fully comparable to the alternative, the payment to the cogenerator of the full cost of the alternative would be just and reasonable to the utility’s customers. Thus we have diffi- culty in describing some particular price other than the avoided cost as being just and reasonable to the utility's customers; and difficulty in giving the Conference Report language cited above any precise mean- ing in a particular situation, other than that some price below the avoided cost is also just, reasonable, and permitted by statute. We do not understand the prescription that the proper price is the lower of the just and reasonable price and the avoided cost as requiring that the selling QF be restricted to a minimal mark-up from its marginal gener- ation cost on its sales to a utility. 31 larly, if a pool has coordinated planning for capacity addi- tions, the pool’s method of sharing those costs should be considered, and in some instances utilized, in determining a pool member’s avoided capacity costs. As in the case of purchases by Fs, the rules for sales by s should permit sufficient latitude to allow “contractual pooling” among Fs to “firm up” capacity available to utili- ties. Such pooling could permit such things as coordinated scheduling for maintenance which would increase the as- sured availability of capacity to the utility. Although this may assure increased generating capacity, further consid- eration should be given to the potential impact on transmis- sion costs of such arrangements. Section 210(b) also requires that the rates for the pur- chases by the electric utilities not discriminate against Fs. It is not clear whether the statute only bars discrimination against Fs as a class, or whether it would also bar dis- crimination among s. If the latter, this may create some practical problems in administration. Since the price to be paid for the purchases by the utility is dependent, in part, on the utility’s avoided costs, and these costs will vary over time and with the number and magnitude of cogeneration arrangements previously entered into, the rates paid will probably have to differ from one arrangement to another depending on when they were entered into and what future costs are being avoided. Further, as with multiple simulta- neous interchange transactions, some priority among Fs may have to be established to determine which is viewed as dispiacing the utility’s highest cost alternative power. Some vintaging arrangement or consistent formulary approach to the computation of the costs avoided may be considered in the rule for the purpose of determining whether the rates discriminate among qualifying facilities. Under certain circumstances it may be desirable to allow a cogenerator or small power producer to sell all its output to a utility and at the same time purchase all its needs from the utility. Specifically, where a utility needs additional ca- pacity, and one of its customers can build and operate a new generator more cheaply than the utility can, it would be in everyone’s interest for the QF to build the unit. How- 32 ever, if the utility’s embedded cost-based rates even after it built the new plant are lower than the incremental cost of power from the new facility the QF would have built, then it would be in the QF’s interest to let the utility build the plant and supply its needs. Put another way, if a QF were prohibited from buying from and selling to a utility simulta- neously, it would be compelled to “buy” from itself at its marginal cost. Where this is lower than the utility’s rate based on average embedded cost, then the QF would still build the facility, as it should in this situation; but where the utlity’s rate is lower than the QF’s marginal cost, the wise firm would allow the utility to build and operate the new plant, even though it cannot do so as cheaply as the QF. This problem only arises where a new facility is in- volved. We have no idea how often the costs would be such that the more costly plant would be built'? but since the utility’s customers would benefit whenever a QF builds a lower-cost plant than the utility can build, we tentatively recommend that this simultaneous buying and selling be permitted in connection with new facilities.“ With regard to existing facilities, however, the situation is exactly the reverse. Here, permitting a customer who has been providing part or all of its own power needs to sell to a utility at or near the utility’s incremental cost and si- multaneously buy back the same power at average em- bedded cost would drive up the costs of power to the utili- ty’s other castomers without doing anything to encourage new cogeneration or desirable kinds of small power produc- tion. Thus we would recommend that the rule prohibit this practice. 1 Unfortunately, it is quite possible that the difference in the in- vestment tax credits which may be available to, respectively, a utility and an owner of a QF will distort this cost comparison. Under the provisions of the Fuel Use Act of 1978, the sale of more than 50% of the output of a new installation would give the facility the status of an electric power plant. As a consequence, absent exemption on other grounds, a cogenerator could not use oil or gas as the basic generation fuel. However, the Fuel Use Act does not apply to installa- tions consuming less than 100 million Btus per hour. 33 As indicated in the preceding section, the ratemaking as- pects of the interconnection costs may be handled in a vari- ety of ways. Depending upon the size and type of generat- ing equipment a QF has, whether or not the QF wants to operate in parallel with the interconnected utility, and the extent to which the QF expects to sell to the utility, many different types of facilities and arrangements may be ap- propriate. In many situations, all the required facilities may not be placed on the QF’s facilities or at the point of in- terconnection; rather, it may be necessary for the utility to install or modify equipment elsewhere on the system in or- der to protect its and QF’s equipment and operations. While we are of the view that the authority to order in- terconnections is inherent in the Commission’s other pow- ers under Section 210, we do not regard this as settling the question of who bears the attendant cost. As to this ques- tion, we think the proscription against compelling to the utility’s customers to subsidize Fs is dispositive: the QF should pay the reasonable costs of the interconnection nec- essary and appropriate to its circumstances. By the same token, however, the comparable costs attending the pur- chase or supplying of the same electric energy from an alternative source should be taken into account in de- termining the price the utility should pay the QF for electricity. The recovery of the utility’s costs of interconnection can be accomplished in either of two ways: through a lump-sum hook-up charge, or through a credit (where the utility is buying from the QF) or surcharge (where the QF is buying from the utility) to the basic price. Where these facilities’ costs are to be amortized over a period of years or volume of sales, it would seem reasonable to allow the utility to se- cure its investment in some manner where either the finan- cial integrity of the QF or the duration of the arrangement are in question. As this entire discussion of pricing and interconnection indicates, the variety of arrangements that might be made between s and utilities is enormous. Therefore, we would recommend that the Commission promulgate broad general rules in the nature of guidelines, leaving flexibility for the States to experiment and accommodate local circum- stances, and leaving room for the parties to negotiate the particular terms and conditions of their arrangements with- in the broad parameters of the Commission’s rules. Under this approach, the States and the Commission would func- tion more as arbitrators of disputes the parties can not re- solve than as traditional regulators. This approach is, in our view, practically unavoidable with regard to the sales by Es to utilities. On the other hand, as noted above, the sale from utilities to s is in most instances the type of trans- action the States now regulate, and continuation of this regulation without substantial change is certainly a real option. Finally, we must observe that the arbitration of disputes approach espoused above is not appropriate where a utility is participating in the ownership or even the operation of a QF. We would recommend that the specific terms of such arrangements be scrutinized by the States to ensure that the pricing or other provisions are not unduly discriminato- ry or beneficial. Environmental Impact Statement It appears to us that an environmental impact statement will not be necessary for Section 210 alone. We reach this preliminary conclusion on the basis that most of the effect of Section 210 flows from statutory mandates as to which the Commission has little or no discretion the requirement that utilities buy from and sell to QFs; the requirement that the Commission grant exemptions necessary to en- courage s (through it is not authorized to grant exemp- tions from environmental laws or regulations); and the re- quirement that prices be set within certain guidelines. In other words, we do not think that the Commission’s adop- tion of one set of rules rather than another on those mat- ters as to which the Commission has discretion or flexibility would constitute a major Federal action significantly affect- ing the quality of the human environment. There does exist some question in our minds, though, as to whether the Section 201 rules together with the Section 210 rules will establish the fuel use and fuel efficiency standards for qualifying cogenerators and qualifying small power producers; and the Section 210 rules will describe with some greater specificity than does the statute the ben- efits of qualification. The environmental impact of this part of PURPA (whether or not the impact is significant) will be a product of the two rules acting together. As stated elsewhere in this memorandum, we anticipate that the number, size, and kind of Fs that will develop vill vary considerably from state to state and region to re- gion. Similarly, the amount and kinds of utility fuel dis- placed by Fs will differ significantly around the country. As a consequence, the states would appear to be in a very good position to provide the information from which the Commission can determine whether the Section 201 and 210 rules would have a significant effect on the quality of the human environment and whether that effect will be benefi- cal or detrimental. Therefore, we recommend that the Commission promptly invite comment from the States in particular and the public in general on this matter so that, at the least, there will be a basis for an assessment of envi- ronmental impact. End of Memorandum. Written Comments Interested persons are invited to submit written com- ments on this staff paper to the Office of the Secretary, Federai Energy Regulatory Commission, 825 North Capitol Street, N.E. Washington, D.C. 20426. Comments should reference Docket No. RM79-55 on the outside of the envel- ope and on all documents submitted to the Commission. Fifteen (15) copies should be submitted. All comments and related information received by the Commission by Au- gust 1, 1979, will be considered prior to the promulgation of final regulations. By the Commission. KENNETH F. PLUMB, Secretary. (FR Doc. 79-304 13 Filed 7-2-79; 8:45 am] Billing Code 6450-01-M UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION [18 CFR Part 292 Docket No. RM79-55 SMALL POWER PRODUCTION AND COGENERATION FACILITIES— RATES AND EXEMPTIONS NOTICE OF PROPOSED RULEMAKING REGARDING THE IMPLEMENTATION OF SECTION 210 OF THE PUBLIC UTILITIES REGULTORY POLICIES ACT OF 1978 (Issued October 18, 1979) Section 210(a) of the Public Utility Regulatory Policies Act of 1978 (PURPA) requires that the Commission pre- scribe rules as it determines necessary to encourage cogen- eration and small power production, requiring electric utili- ties to offer to: (1) sell electric energy to qualifying cogeneration facil- ities and qualifying small power production facili- ties, and (2) purchase electric energy from such facilities. In addition, section 210 e) of PURPA requires the Com- mission to prescribe rules under which qualifying cogenera- tion and small power production facilities are exempted, in whole or in part, from the Federal Power Act, from the Public Utility Holding Company Act of 1935, and from State laws and regulations respecting the rates or respect- ing the financial or organizational regulation of electric util- ities, if the Commission determines such exemption is nec- essary to encourage cogeneration and small power production. On June 26, 1979, in Docket No. RM 79-54, the Commis- sion issued proposed rules regarding the determination of which cogeneration and small power production facilities are quaiifying cogenration facilities or qualifying small pow- er production facilities. Such qualifying facilities are enti- tled to avail themselves of exemptions set forth in section 210 of PURPA, and are eligible for exemption from the in- 37 cremental pricing provisions of section 206(c) of the Natural Gas Policy Act of 1978 (Order No. 49, 5 282.203(e), issued September 28, 1979, 44 F. R. 57726). On June 27, 1979, in Decket No. RM79-55, the Commis- sion issued a Staff discussion paper regarding issues arising under section 210 of PURPA.' The Staff discussion paper set forth many legal and policy questions arising under sec- tion 210 of PURPA. In addition to those issues, comments received in response to the Staff discussion paper and in the public hearings held in San Francisco, Chicago, and Washington, D.C. in July, 1979 on this topic raised new questions regarding the Commission's responsibility to ex- ereise its authority under section 210. The Commission has taken into consideration these questions and comments in developing this proposed rulemaking. SUMMARY The proposed rules provide that electric utilities must purchase electric energy and capacity made available by qualifying cogenerators and small power producers at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and capacity from these sources, rather than generating an equivalent amount of energy itself or purchasing the energy from other suppli- ers. To enable potential cogenerators and small power pro- ducers to be able to estimate these avoided costs, the rules require electric utilities to furnish data with regard to pres- ent and future costs of energy and capacity on their systems. These rules also provide that electric utilities must fur- nish electric energy to qualifying facilities on a nondiscrim- inatory basis, at a rate that is just and reasonable and in the public interest, and must provide certain types of serv- line for the filing of comments on the Staff discussion paper was not extended beyond the original deadline of August 1, 1979. ice which may be requested by qualifying facilities to sup- plement or back up those facilities’ own generation. The rule exempts all qualifying cogeneration facilities and certain qualifying small power production facilities from rate and certain other regulations under the Federal Power Act, from the provisions of the Public Utility Hold- ing Company Act of 1935 related to electric utilities, and from State laws regulating electric utility rates and finan- cial organization. The implementation of these rules is reserved to the State regulatory authorities and nonregulated electric elec- tric utilities. Within one year of the issuance of the Com- mission’s rules, each State regulatory authority or nonreg- ulated utility must implement these rules. That implemen- tation may be accomplished by the issuance of regulations, on a case-by-case basis, or any other means reasonably de- signed to give effect to the Commission's rules. The Commission observes that this rulemaking repre- sents an effort to evolve concepts in a newly developing area within rigid statutory constraints. The Commission is attempting to afford broad discretion to the State regula- tory authorities and nonregulated electric utilities in recog- nition of the variety of institutional, economic, and local circumstances which may be affected by this proposed rule- making. In this regard, the Commission seeks the fullest range of comments on the legal authority of proposed Com- mission action, and on the technical and practical aspects of the proposals set forth in this rulemaking. SECTION-BY-SECTION ANALYSIS SUBPART A—Arrangements Between Electric Utilities and Qualifying Cogeneration and Small Power Production Facilities under Section 210 of the Public Utilities Regula- tory Policies Act of 1978. § 292.101 Scope. Section 292.101(a) describes the scope of Subpart A of Part 292 of the Commission’s rules. Subpart A applies to sales and purchases of electric energy and capacity between qualifying cogeneration and small power production facili- ties and electric utilities, and actions related to such sales and purchases. Section 292.101(b) provides that the author- ity of this subpart does not preclude negotiated agreements between qualifying cogenerators or small power producers and electric utilities which differ from rates or terms which would otherwise be required under this subpart. Paragraph (b)(1) reflects the Commission's view that the rate provi- sions of section 210 of PURPA apply only if a qualifying cogenerator or small power producer chooses to avail itself of the rights and protections set forth in that section. An agreement between an electric utility and a qualifying cogenerator or small power producer to conduct sales or purchases at rates higher or lower, or under terms or con- ditions different from those set forth in these rules, does not violate the Commission’s rules under section 210 of PURPA. Nor would provisions of State law or regulations which provide different incentives for small power produc- tion and cogeneration (than are provided in the Commis- sion’s rules) be preempted. The Commission recognizes that the ability of a qualifying cogenerator or small power producer to negotiate with an electric utility is buttressed by the existence of the statutory rights and protections of these rules, and the right of State regulatory agencies and nonregulated electric utilities to provide further encourage- ment fo these technologies. If, prior to the existence of the rights and protections set forth in PURPA, a cogenerator or small power producer entered into a contractual agreement by which he received sufficient financial incentive to sell his electric output to a utility, the encouragement of cogeneration or small power production does not require that he be given additional in- centives. Accordingly, paragraph (b)(2) provides that Sub- part A will not affect the validity of any contract between a qualifying cogenerator of small power production facility and an electric utility. At the expiration of the contract, a cogenerator or small power producer will be able to avail himself of these rules. § 292.102 Definitions. This section contains definitions applicable to Subpart A. 40 Paragraph (a) provides that terms defined in PURPA have the same meaning as they have in PURPA, unless fur- ther defined in this part of the Commission's regulations. Subparagraph (1) defines a qualifying facility as a cogen- eration or small power production facility which is a quali- fying facility under § 292.208 of the Commission’s regula- tions. Those regulations implement section 201 of PURPA, and are the subject of Docket No. RM 79-54. Subparagraph (2) defines “purchase” as the purchase of electric energy or capacity from a qualifying facility by an electric utility. Subparagraph (3) defines “sale” as the sale of electric en- ergy or capacity by an electric utility to a qualifying facility. Subparagraph (4) cefines “system emergency” as a condi- tion on a utility’s system which is likely to result in disrup- tion of service to a significant number of customers or is likely to endanger life or property. Subparagraph (5) defines rate“ as any price, rate charge, or classification made, demanded, observed, or received with respect to the sale or purchase of electric en- ergy or capacity, or any rule, regulation, or practice re- specting any such rate, charge, or classification, and any contract pertaining to the sale or purchase of electric ener- gy or capacity. Subparagraph (6) defines “avoided costs” as the costs to an electric utility of energy or capacity or both which, but for the purchase from a qualifying facility, the electric utili- ty would generate or construct itself or purchase from an- other source. This definition is derived from the concept of “the incremental cost to the electric utility of alternative electric energy” set forth in section 210(d) of PURPA. It in- cludes both the fixed and the running costs on an electric utility system which can be avoided by obtaining energy or capacity from qualifying facilities. The costs which an electric utility can avoid by making such purchases generally can be classified as “energy” costs or “capacity” costs. Energy costs are the variable costs as- sociated with the production of electric energy (kilowatt- hours). They represent the cost of fuel, and so ne operating 41 and maintenance expenses. If, by purchasing electric ener- gy from a qualifying facility, a utility can reduce its energy costs or can avoid purchasing energy from another utility, the rate for a purchase from a qualifying facility is to be based on those energy costs which the utility can thereby avoid. Capacity costs are the costs associated with providing the capability to deliver energy; they consist primarily of the capital costs of facilities. If a qualifying facility offers energy of sufficient reliability and with sufficient legally en- forceable guarantees of deliverability to permit the pur- chasing electric utility to avoid the need to construct a generating unit, to enable it to build a smaller, less expen- sive plant, or to purchase less firm power from another util- ity, then the rates for such a purchase will be based on the net avoided capacity and energy costs. 2 “Net avoided costs” are the excess of the total costs of the system developed in accordance with the utility's optimum capacity expansion plan, excluding the qualifying facility, over the system's total costs (before payment to the qualifying facility) developed in accordance with the utility’s optimum capacity expansion plan including the quali- fying facility. This concept recognizes that the energy cost associated with a deferred or avoided unit may be different from the energy costs of the qualifying facility which permitted that deferral or avoidance. In determining an optimum capacity expansion plan, a utility must con- sider both capacity and energy costs in order to minimize the antic- ipated total system costs. In providing for payments for avoided capac- ity, the Commission uses the term “net avoided cost” in recognition of the fact that various types of capacity will not produce the same amount of energy, so that some change in the dispatch of generation may be necessary from the remaining plants after a planned unit is de- ferred and the qualifying facility's capacity is substituted along with other available capacity to produce the same amount of energy at the minimum cost. This is particularly true, for example, where the capaci- ty factor for the qualifying facility is less than the planned capacity fac- tor from a base load (high capacity cost—low energy cost) alternative facility which is deferred. In such a case, although adequate capacity may exist on the system due to the purchase from the qualifying facili- ty in lieu of the deferred base load unit, additional energy costs may be incurred due to increased generation from intermediate plants to make up the difference between the planned generation from the base load plant and the lesser total energy produced by the qualifying facility. Such increased energy cost is appropriately recognized by providing 42 There is considerable language in both the statute and the Conference Report, as well as the Federal Power Act, in support of the proposition that capacity payments are not only legally permitted to be required by the Commis- sion, but also, at least in some circumstances, mandated. The Conference Report addresses the calculation of the alternative cost standard at some length. The final para- graph of this section of the Report is the following: The conferees expect that the Commission, in judging whether the electric power supplied by the cogener- ator or small power producer will replace future power which the utility would otherwise have to generate it- self either through existing capacity or additions to ca- pacity or purchase from other sources, will take into account the reliability of the power supplied by the cogenerator or small power producer by reason of any legally enforceable obligation of such cogenerator or small power producer to supply firm power to the utih- ty. The references to “additions to capacity” and to obliga- tions “to supply firm power” (the rates for which, in this Commission’s experience, always include a capacity compo- nent) lead the Commission to the conclusion that, under Section 210, capacity payments to qualifying facilities can be required under certain circumstances; and that a utility’s refusal to make payments based in part on avoided capacity payments could be discriminatory. In addition, the Commission notes that the statutory lan- guage used in the Federal Power Act uses the term “elec- tric energy” to describe the rates for sales for resale in interstate commerce. Demand or capacity rates are a tradi- tional part of such rates. The term “electric energy” is used throughout the Act to refer both to electric energy and ca- pacity. The Commission does not find any evidence that the term “electric energy” in section 210 of PURPA was in- for the payment to the qualifying facility of the „et avoided costs. In this way, the ratepayers are assured of paying no more than the total costs that would have been incurred had the unit not been deferred. Conference Report on H.R. 4018, Public Utilities Regulatory Poli- cies Act of 1978, H. Rep. No. 1750, 99, 95th Cong., 2d Sess. (1978) 43 tended to refer only to fuel and operating and maintenance expenses, instead of all of the costs associated with the pro- vision of electric service. To interpret this phrase to include only the energy would lead to the conclusion that the rates for sales to qualifying facilities only include the energy component of the rate. It is the Commission’s belief that this was not the intended re- sult, and thus provides an additional reason to interpret the phrase electric energy to include both energy and capacity. § 292.103 Availability of Electric Utility System Cost Data. In order to be able tu evaluate the financial viability of a cogeneration or small power production facility, an investor needs to be able to ascertain, before construction of a facili- ty, the expected return on a potential investment. This re- turn will be determined in part by the price at which the qualifying facility can sell its electric output. Under § 292.105 of these rules, the rate at which a utility must purchase that output is based on the utility's avoided costs. In order to provide data to qualifying facilities which will assist them in determining the utility’s avoided costs, § 292.103(b) of the rules requires electric utilities to make available to cogenerators and small power producers data concerning the present and anticipated future costs of ener- gy and capacity on the utility’s system. The data required to be provided to determine these avoided costs will have been prepared in compliance with the Commission’s rules implementing section 133 of PURPA.* This section wil! thus, for the most part, require a table presenting data al- ready developed. For example, § 290.303(h) of the Commission's rules implementing section 133 of PURPA requires such electric utilities to report margin- al energy costs for each month of the reporting period and for each month of the next five years. Section 290.302(g) of these rules requires electric utilities to report the estimated cost, in dollars per kilowatt of generation, of generation units likely to be installed to meet increases in peak demand. Section 290.302(f) requires the reporting of estimates, for the next ten years of information regarding total s tem capacity, and capacity to be supplied by other utilities. 44 Section 133 of PURPA applies to each electric utility whose total sales of electric energy for purposes other than resale exceeded 500 million kWh during any calendar year beginning after December 31, 1975, and before the immedi- ately preceding calendar year. (The phrase “before the im- mediately preceding calendar year” refers to the year two years prior to the current year. For example, if an electric utility exceeded the 500 million kWh limit both during 1976 and 1979, it must comply with section 133 requirements in 1981.) Section 290.102(d) of the Commission’s rules imple- menting section 133 of PURPA granted an extension until June 30, 1982,5 to electric utilities covered by that section having total sales of energy for purposes other than resale of less than 1 billion kWh in each of the calendar years 1976, 1977, and 1978. The proposed coverage under paragraph (a) of these reg- ulations is the same as that provided pursuant to section 133 of PURPA and the Commission’s rules implementing that section, with an exception provided in paragraph (c) as will be discussed. Paragraph (b) provides that each regulated electric utili- ty must furnish to the State regulatory authority, and maintain for public inspection, data related to the costs of energy and capacity of the electric utility’s system. Each nonregulated electric utility must maintain such data for public inspection. Subparagraph (1) requires each electric utility to provide the estimated avoided cost of energy on its system for various levels of purchases from qualifying facilities. The levels of purchases are to be stated in blocks of one hun- dred megawatts or less for systems with peak demand of 1000 megawatts or more, and in blocks equivalent to not more than ten percent of system peak demand for systems less than 1000 megawatts. This information is to be stated 5 Docket No. RM79-6, issued June 5, 1979, granted an extension un- til May 31, 1982, to electric utilities having total sales of electric ener- gy for purposes other than resale of less than 1 billion kilowatt-hours in each of the calendar years 1976, 1977, and 1978. The Commission re- cently issued revised regulations in this docket which extended this date to June 30, 1982. 45 on a cents per kilowatt-hour basis, for daily and seasonal peak and off-peak periods, for the immediately preceding year, and on an estimated cents per kWh basis for the cur- rent calendar year and for each of the next five years. Subparagraph (2) requires each electric utility to provide its schedule for the addition of capacity, planned purchases of firm energy and capacity, and planned capacity retire- ments for each of the next 10 years. Subparagraph (3) requires each electric utility to provide the estimated costs at completion, on the basis of dollars per kilowatt, of planned capacity additions, including planned firm purchases. Qualifying facilities may wish to sell energy or capacity to electric utilities which are not subject to the reporting requirements of paragraph (b). In that event, paragraph (c) provides that, upon request of a qualifying facility, an elec- tric utility not otherwise covered by paragraph (b) must provide sufficient data to enable the cogenerator or small power producer to determine the utility’s avoided costs. If such utility refuses to supply the requested data, the quali- fying facility may apply to this Commission for an order requiring that the information be supplied. The Commis- sion, in considering such applications, will take into account the burden on the facility. A non-generating electric utility which does not own or plan to acquire generating capacity may incorporate the data provided by each of its supplying utilities in its compli- ance with the provisions of this section. § 292.104 Electric Utility Obligations Under This Subpart. Section 210(a) of PURPA provides that the Commission shall prescribe rules requiring electric utilities to offer to purchase electric energy from qualifying facilities. The Commission interprets this provision to impose on electric utilities an obligation to purchase all electric energy and ca- pacity made available from qualifying facilities, except dur- ing periods prescribed in § 202.105(e) and during system emergencies. There are several circumstances in which a qualifying fa- cility might desire that the electric utility with which it is 46 interconnected not be the purchaser of the qualifying facili- ty’s energy and capacity, but would prefer instead that an electric utility with which the purchasing utility is intercon- nected make such a purchase. If, for example, the purchas- ing utility is a non-generating facility, its avoided costs will be the price of bulk purchased power ordinarily based on an average figure representing the average cost of energy and capacity on the supplying utility’s system. As a result, the rate to the qualifying facility would be based on those aver- age costs. If, however, the qualifying facility’s output were purchased by the supplying utility, its output could replace energy supplied by specific peaking units, and its capacity might enable the supplying utility to avoid the addition of new capacity. The costs, and thus the avoided costs, of peaking energy and new capacity are generally greater than system average figures. Under these proposed rules, certain small electric utili- ties are not required to provide system cost data, except upon request of a qualifying facility. If, with the consent of the qualifying facility, a small electric utility chooses to transmit energy from the qualifying facility to a second electric utility, the small utility can avoid the otherwise ap- plicable requirements that it provide the system cost data for the qualifying facility and that it purchase the energy itself. Accordingly, paragraph (d) provides that a utility which receives energy or capacity from a qualifying facility may, with the consent of the qualifying facility, transmit such en- ergy to another electric utility. However, if the first utility does not transmit the purchased energy or capacity, it re- tains the purchase obligation. Any electric utility to which such energy or capacity is delivered must purchase this en- ergy under the obligations set forth in these rules as if the purchase were made directly from the qualifying facility.“ he Commission notes that while a purchase from a qualifying fa- cility may have value as energy and capacity, what is actually trans- mitted to the second utility is properly described as electric energy. The utility to which energy is transmitted, however, must pay rates based on energy and capacity value. 47 The costs of transmission are not a part of the rate which an electric utility to which energy is transmitted is obli- gated to pay the qualifying facility. These costs are part of the costs of interconnection, and are the responsibility of the qualifying facility under § 292.108 of these rules. How- ever, pursuant to agreement between the qualifying facility and any electric utility which transmits electric energy on behalf of the qualifying facility, the transmitting utility may share the costs of transmission. The electric utility to which the electric energy is transmitted has the obligation to purchase the energy at a rate which reflects the costs that it can avoid as a result of making such a purchase. Paragraph (b) sets forth the statutory requirement of section 2100) of PURPA that electric utilities offer to sell electric energy to qualifying facilities. This section creates a Federal right for qualifying facilities to obtain electric service, in addition to any service the electric utility is obli- gated to provide under State laws. The State discussion paper dealt with the issue of wheth- er there is inherent in section 210 of PURPA the authority to order interconnections between eiectric utilities and qualifying facilities, or whether qualifying facilities must use the procedures set forth in the new sections 210 and 212 of the Federal Power Act to gain interconnection.’ The Commission believes that the requirement to interconnect is within the legal authority to the Commission under sec- tion 210 of PURPA, particularly subsumed within the re- quirement to buy and sell. To hold otherwise would mean that Congress intended to have qualifying facilities go through an extended and expensive proceeding simply to gain interconnection, contrary to the entire thrust of sec- tions 201 and 210 of PURPA. These sections evince the clear Congressional intent to encourage development of these desirable forms of genera- tion, and to have the commercial development of these fa- cilities proceed expeditiously. In other words, Congress has already made the judgment that these kinds of facilities serve one of the purposes of the Act as set sut in section Staff discussion paper, supra., at 10-14. 101, viz, “the optimization of the efficiency of use of facili- ties and resources by electric utilities”, and it would be both redundant and unduly burdensome to have the spon- sors of individual facilities show in an evidentiary hearing conducted under section 210 of the Federal Power Act that their project in particular would serve this end (or one of the other related goals established as criteria for an inter- connection order in section 210(c)(2)). The purpose of an in- terconnection application, whether under section 202 or 210 of the FPA, is to secure service, whether emergency or otherwise; and section 210 of PURPA establishes the en- titlement of a qualifying facility to service from the inter- connected utility. In effect, the proponents of the view that a qualifying facility must apply under sections 210 and 212 of the FPA have the burden of showing that Congress in- tended inerconnection and the entitlement to buy and sell be denied to a qualifying facility which is unable to make the showings required by those sections, especially in light of the fact that a previously interconnected customer in- stalling qualifying facilities would not have to so apply. This is not to say that all of the protections that Congress has given the target of an interconnection application in sections 210 and 212 of the FPA are necessarily absent from section 210 of PURPA. The Conference Report on section 210 states that customers of utilities are not to be compelled to subsidize qualifying facilities, and this princi- ple would seem to bear on the question of who pays the costs of interconnection as well as on the pre-unit price to be paid for energy. On the other hand, the Conference Re- port includes a proscription against “unreasonable rate structure impediments, such as unreasonable hook up charges.” This provides another argument in favor of read- ing section 210 of PURPA as including interconnection au- thority, since the elaborate cost determination required un- der sections 210 or 212 of the FPA is redundant if the costs of interconnection are viewed simply as a feature of the rate structure with the charge therefor based on the cost of the utility. However, the Commission does view section 210 of the FPA as an alternate avenue for remedy available to any qualifying facility which wishes to apply under it. 49 The obligation to interconnect can be part of either an electric utility’s option to purchase from or sell to a quali- fying facility. With regard to the obligation to sell, State law ordinarily sets out the obligation of an electric utility to provide service to customers located within its service area. The Commission believes that State law will normally impose on an electric utility the obligation to interconnect and that the Commission’s proposal will not, in most in- stances, impose any additional obligation on electric utilities. As noted in the Staff discussion paper, by installing cer- tain equipment, an electric utility can be protected from disruption of its operations caused by a qualifying facility. The Commission has not received comments which disagree with this understanding. Therefore, through the allocation of the costs associated with such equipment to the quali- fying facilities, as provided in § 292.109, and through the imposition of standards for operating reliability under § 292.110, appropriate physical and financial protection for the electric utilities is provided in the Commission’s pro- posed rules. Several commentators urged that the Commission re- quire electric utilities to offer to operate in parallel with a qualifying facility. By operating in parallel, a qualifying fa- cility is enabled automatically to export any electric energy which is not consumed by its own load. Therefore, provided that the qualifying facility complies with the standards set forth in § 292.110 regarding operating reliability, the Com- mission proposes in paragraph (e) that electric utilities be required to offer to operate in parallel with a qualifying facility. § 292.105 Rates for Purchases Section 210(b) of PURPA provides that in requiring any electric utility to purchase electric energy from a qualifying facility, the Commission must insure that the rates for such purchases be just and reasonable to the electric consumers of the purchasing utility, in the public interest, nondiscrim- inatory to qualifying facilities, and that they not exceed the incremental costs of alternative electric energy (the costs of energy, which, but for the purchase, the utility would gen- erate from another source). Types of Purchases In implementing this statutory standard, it is helpful to review industry practice respecting sales bet ween utilities. Sales of electric power are ordinarily classified as either firm sales, where the seller provides power at the custom- er’s request, or non-firm power sales, where the seller and not the buyer makes the decision whether or not power is to be available. Rates for firm power purchases include payments for the cost of fuel and operating expenses, and also for the fixed costs associated with the construction of generating units needed to provide power at the purchas- er’s discretion. The degree of certainty of deliverability re- quired to constitute “firm power” can ordinarily be ob- tained only if a utility has several generating units and adequate reserve capacity. The capacity payment, or de mand charge, will reflect the cost of the utility’s generating units and the associated costs of assuring that firm power will be available on demand. In contrast, the ability to provide electric power at the selling utility’s discretion imposes no requirement for the construction of capacity on the seller. In order to provide power to customers at the seller’s discretion, the selling utility needs only to provide for the cost of operating its generating units. These costs, called “energy” costs, ordi- narily are the ones associated with non-firm sales of power. Purchases of power from qualifving facilities will fall somewhere on the continuum between these two types of electric service. Thus, for example, wind machines that fur- nish power only when wind velocity exceeds twelve miles per hour may be so uncertain in availability of output as only to permit a utility to avoid generating an equivalent amount of energy. The utility must continue to provide ca- pacity that is available to meet the needs of its customers. Rates for such sporadic purchases should thus be based on utility system’s avoided incremental cost of energy (system lambda), and not based on avoided capacity. 51 On the other hand, photovoltaic cells, although subject to some uncertainty in power output, have the general advan- tage of providing their maximum power coincident with the system peak when used on a summer peaking system. The value of such power is greater to the utility than power de- livered during off-peak periods. Since the need for capacity is based on system peaks, the qualifying facility's coinci- dence with the system peak should be reflected in the al- lowance of some capacity’ value and an energy component that reflects the avoided energy costs at the time of the A facility burning municipal waste or biomass can oper- ate more predictably and reliably than solar or wind sys- tems. It can schedule its outages during times when demand on the utility’s system is low. If such a unit demon- strates a degree of reliability that would permit the utility to defer or avoid construction of a generating unit or the purchase or firm power from another utility, then the rate for such a purchase should be based on the avoidance of both energy and the capacity costs. In order to be able to defer or cancel the construction of new generating units, a utility must obtain a commitment, sufficiently ahead of the lead time for the construction of its own new capacity, that provides contractual or other legal- ly enforceable assurances that capacity from alternative sources will be available. If a qualifying facility makes such a commitment, the Commission believes that, as a matter of both policy and interpretation of section 210, the quali- fying facility is entitled to receive rates based on the utili- ty's avoided costs resulting from the capacity of qualifying facility supplies. Moreover, if a cogenerator or small power producer were permitted to receive only the energy (fuel, and operating and maintenance) expenses which the pur- chasing utility can avoid—while the cogenerator or small power producer must himself invest in new, and often high- ly capital-intensive, machinery—these potential sources of energy may go undeveloped. In light of the Commission's statutory obligation to encourage cogeneration and small power production, the Commission believe that a proper in- terpretation of “the incremental costs of alternative electric energy” requires that, when purchases of energy can sub- stitute for intermediate, or base-load, the rate to the cogen- erator or small power producer include the net avoided ca- pacity and energy costs. If a qualifying facility opts to receive rates based on avoided energy costs, such rates should reflect the energy costs of the electric utility’s units which otherwise would have been operated. The Commission believes that there are a variety of acceptable ways to carry out this policy at the State level. The general concept here is that rates for purchases from the qualifying facility would be based on the highest energy cost unit then operating. The qualifying facility would continue to be dispatched until the cost of en- ergy costs is lower than the price at which the qualifying facility wishes to sell. The Commision neither expects nor requires that the de- termination of utilities’ avoided costs will be so precise. By definition, these costs are based on estimates of costs which would be incurred if certain events were to take place. Electric rates are ordinarily calculated on the basis of aver- aging. So long as a rate for purchases reasonably accounts for the avoided costs, and does not fail to provide the re- quired encouragement of cogeneration and small power production, it will be considered as implementing these rules. Paragraph (a) therefore provides that the statutory re- quirements regarding rates for purchases of energy and ca- pacity from a qualifying facility as satisfied if the rates re- flects the avoided costs resulting from such a purchase as determined on the basis of the cost of energy and capacity set forth pursuant to § 292.103(b) or (e). Method of Implementation The Commission is required under section 210 of PURPA to prescribe rules requiring electric utilities to offer to sell electric energy to and purchase elecric energy from quali- fying facilities. Paragraphs (b) and (c) of section 210 set forth the standards regarding the rate at which such pur- chases and sales shall be made. The implementation of Commission rules promulgating these standards is reserved to the State regulatory authorities and nonregulated util- _ ities,which are required under section 210(f) to implement the Commission’s rules. One major area of concern expressed in comments re- ceived from electric utilities, cogenerators and small power producers, and State regulatory authorities has been that the Commission’s rules should state general principles suffi- cient to leave the states and non-regulated utilities flexibili- ty.* The basis for this recommendation is the need for ex- perimentation in a new technological area and in an area that is subject to a variety of State procedures, the diverse nature of cogeneration and small power production sys- tems, and the differences in the costs of energy and capaci- ty on individual electric systems. As a result, while we herein propose that, for example, capacity costs must be paid if a utility can actually avoid the construction or pur- chase of capacity, our rules will not dictate the method by which such a payment is to be determined. Rather the Commission proposes to leave the selection of a methodol- ogy to the States and nonregulated electric utilities, with the understanding that should a State or nonregulated utili- ty not fulfill the intent and purposes of our rules and of sec- tion 210 of PURPA, the Commission and others have avail- able the enforcement power set forth in section 210(h) of PURPA to assure compliance. Additionally, the Commis- sion is authorized to revise these rules in the future to pro- vide greater specificity to these rules if that is necessary. Paragraph (b) requires electric utilities, on request of a qualifying facility, to promulgate a tariff or other method for establishing rates for purchases from qualifying facili- ties of ten kilowatts or less. In Docket No. RM79-54 the Commission proposed a minimum size limitation for quali- fying facilities of ten kilowatts. However, comments re- ceived in response to that proposed rulemaking indicate that such a limitation could hamper the development of Comments of American Electric Power, filed August 1, 1979, at 2-3; Comments of Electric Consumer Resource Council (ELCON), filed August 1, 1979, at 6; Comments of the National Association of Regula- tory Utility Commissioners (NARUC), filed August 1, 1979, at 2-5. auxiliary solar and wind power units. Without finally deter- mining that question in this rulemaking, it appears to the Commission that the burden of interconnected operation on both utilities and qualifying facilies can be minimized if standard tariffs are used. Some utilities already have such tariffs in effect. For units of ten kilowatts or less, it is likely that few changes in the utility’s distribution system would be required. For ex- ample, an electric utility might offer to permit certain cus- tomers to reverse their electric meters, thus permitting consumption by the customer. While the Commission wil! deal more extensively with the matter of a size limtiation for qualifying facilities in its final rule in Docket No. RM79-54, the Commission solicits comment here on the merits of requiring utilities to promulgate tariffs for quali- fying facilities of ten kilowatts or less. Paragraph (e) concerns a problem arising in the imple mentation of the concept of avoided costs. At the time that a qualifying facility delivers electric energy to an electric utility, that utility can determine its system lambda and thus calculate the costs it can avoid by making the pur- chase. Subparagraph (1) therefore provides rates for pur- chases made on an “as available” basis may be based on the purchasing utility’s avoided energy costs. In order to establish certainty of future revenue, a quali- fying facility might seek to obtain a contract from a utility providing that the utility will pay a certain price for energy from a qualifying facility, under specified terms and condi- tions. Indeed, a qualifying facility desiring to obtain capaci- ty credit must provide the purchasing utility with assur- ances that such capacity will continue to be available. In the case of future purchases pursuant to a legally en- forceable obligation, the utility’s avoided energy or capaci- ty costs may be based on the costs of production facilities which are not built and for which the only available cost data are estimates. When the qualifying facility actually supplies electricity, the utility’s avoided costs may deviate from these estimated figures. The Commission believes that these potential deviations are a normal result of risk allocation resulting from contractual commitments or other 55 legal obligations, and believes that they must be permitted if the Commission is to fulfill its mandate to encourage cogeneration and small power production. Accordingly, subparagraph (2) provides tha rates for such purchases may be based on future estimated utility costs of energy or ca- pacity regardless of whether these estimated costs actually track the actual costs that are incurred. Paragraph (d) sets forth factors on the basis of which the State regulatory authority or nonregulated utility should determine a utility’s avoided costs. These principles relate both to the quality of power available from the qualifying facility and its ability to displace or replace energy and ca- pacity on the utility’s system. Subparagraph (1) deals with the availability of capacity from a qualifying facility during system daily and seasonal peak periods. If a qualifying facility can provide energy toa utility during peak periods when the electric utility is run- ning its most expensive generating units, this energy has a higher value to the utility than energy supplied durng off- peak periods during which only units with lower running costs are operating. Ideally, the rates for purchases would reflect the cost in the purchasing utilitys system at the precise moment when such energy is supplied. The me- tering equipment that would be required to ascertain these times of delivery with the requisite specificity may be ei- ther unavailable or prohibitively expensive. To the extent that such metering equipment is available, however, the State or nonregulatory utility should take into account the time at which the purchase from a qualifying facility is made. Clauses (i), (ii), (iii), (iv), and (v) deal with the reliability of a qualifing facility. When an electric utility provides pow- er from its own generating units or from those of another electricity utility, it normally controls the production of such power from a central location. The ability to so control power production enhances a utility’s ability to respond to changes in demand and thereby enhances the value of that 56 power to the utility. A qualifying facility may be able to en- ter into an arrangement with the utility which gives the utility the advantage of dispatching the facility.“ Clause (ii) refers to a qualifying facility’s ability and will- ingness to provide power and energy during system emer- gencies. Section 292.109 of these proposed regulations con- cerns the provision of electric service during system emergencies. It provides that, to the extent that a quali- fying facility is willing to forego its own use of energy dur- ing sytem emergencies and provide power to a utility’s sys- tem, the rate for purchases from the qualifying facility should reflect the value of that service. Small power pro- duction and cogeneration facilities could provide significant back-up capability to electric systems during emergencies. One benefit of the encouragement of interconnected cogen- eration and small power production may be to increase overall system reliability during such emergency condi- tions. Any such benefit should be reflected in the rate for purchases from such qualifying facilities. Clause (iii) deals with periods during which a qualifying facility is unable to provide power. Electric utilities sched- ule maintenance outages for their own generating units at periods during which demand is low. If a qualifying facility can similarly schedule its maintenance outages during peri- ods of low demand, or during periods in which a utility’s ca- pacity will be adequate to handle existing demand, it will enable the utility to avoid the necessity to provide redun- dant capacity. With regard to forced or unscheduled ont- ages, addressed in clause (iv), it is clear that a utility can- not avoid the construction or purchase of capacity if it is likely that the qualifying facility which would replace such capacity may go out of service during the period when the utility needs its power to meet demand. Based on estimated and demonstrated reliability of the qualifying facility, the rate for purchases from a qualifying facility should be ad- justed to reflect its force [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385009_0376%3A03. Public record. Not legal advice.