Ohio Power Co. v. Federal Energy Regulatory Commission

668 F.2d 880, 1982 U.S. App. LEXIS 22722

• Court: Court of Appeals for the Sixth Circuit
• Decided: January 11, 1982
• Docket: Nos. 79-3628, 79-3685 and 79-3698
• Status: Published

Opinions

PHILLIPS, Senior Circuit Judge.

This case is before the court on three petitions to review two orders of the Federal Energy Regulatory Commission¹ in American Electric Power Service Corporation, Docket No. E-9408: “Opinion No. 50, Opinion and Order Approving Amendment of Interconnection Agreement with Modifications,” issued July 27, 1979; and “Order Denying Applications for Rehearing and Clarifying Requirement for Credits of Refunds,” issued September 24, 1979. The order of July 27, 1979, (but not the order of Sept. 24, 1979) is reported at 19 Fed.Pow. Serv. (Matthew Bender) 5-869. Copies of both orders are made an Appendix to this opinion.

The American Electric Power Company, Inc. (AEP) is an electric utility holding company, registered under the Public Utility Holding Company Act of 1935, 15 U.S.C. §§ 79, et seq. Its electric utility subsidiary companies own and operate a physically integrated electric utility system (the AEP System) for the generation, transmission, and sale of electric power and energy in parts of Ohio, Michigan, Indiana, Kentucky, Virginia, West Virginia and a small area in the Tri-Cities section of East Tennessee.

In Indiana & Michigan Electric Company, 33 F.P.C. 739, 743 (1965), aff’d, 365 F.2d 180 (7th Cir.), cert. denied, 365 U.S. 972, 87 S.Ct. 509, 17 L.Ed.2d 435 (1966), the Commission approved the following definition of a physically integrated and centrally controlled electric power system:

Turning to the present record we find that AEP forms a physically integrated and centrally controlled interstate system for the generation, transmission and sale of electric energy. This conception is well defined by Philip Sporn in his book “The Integrated Power System”. Mr. Sporn has been associated with the development of the AEP system, and is a Director of American Electric Power Company, Inc. and Chairman of its System Development Committee.

From a technical standpoint, what is meant by ‘integration’ is this: that all facilities of the system are connected physically into or gathered within the system, and that they all are made to work continuously as part of the system. The presumption is that no facility is needlessly idle; no part of the system is left hanging loose, so to speak; no part of the system is left without the resources and support of the system as a whole.

Applied to energy generation, this means the ability to develop all energy resources capable of economic exploitation and the development of all the resources to their maximum, as well as the elimination of all barriers to development such as local inability to absorb the resources. Again, it means the ability to use the largest units justified by the requirements of the system for any particular station or source, regardless of the requirements of the local area. Still further, it means the ability, as the system grows and develops, to exploit the most efficient units capable of technical projection because other units relatively recently installed but perhaps not so technically advanced can be relegated to a lesser system use. The combined or integrated effect of these is conservation on a vast scale.

Mr. Sporn then discusses the AEP system as an example of an integrated system and considers its growth and development, its ability to serve all requirements of any part of the area and its contribution to operating economies and resource conservation.

In that case the Seventh Circuit described the AEP System as follows:

Indiana & Michigan Electric Company, together with five other operating companies, is an integral part of the American Electric Power System (AEP), a single coordinated power system operating as an integrated unit in Michigan, Indiana, Ohio, Kentucky, West Virginia, Virginia and Tennessee, with generating facilities combined by an inter-connected transmission grid. The System’s dispatching center at Canton, Ohio, directs the dispatch and utilization of energy on a continuous basis to provide the capacity and energy required to carry all the customer demands in the seven-state area at maximum economy.

The proof shows that I & M realizes substantial advantages from its participation in the integrated operations including savings in capital outlay for generating facilities, savings in the cost of generating and transmitting energy, better control and maintenance of voltage levels and greater reliability of service.

The System serves more than 5,400,000 people, and is tied together by a network of 14,000 circuit miles of 345,000 volt line, the highest voltage in general use in the United States. The System is interconnected with nineteen other electric power systems at sixty-six locations, including thirty-nine major, high-voltage interconnections.

The electric load of every customer of every operating company in the System is supplied with electric energy from the entire AEP pool.

365 F.2d at 181-82.

The American Electric Power Service Corporation (AEP Service Corporation), which initiated this proceeding before the Commission, supervises and directs the operation and use of the electric power and energy produced by and available to the system. AEP Service Corporation is a wholly-owned subsidiary of AEP. It renders engineering, rate, financial, accounting, legal and other special services to its parent and to the operating companies. The AEP Service Corporation does not own any facilities for the generation, transmission or distribution of electric power and energy.

The four principal operating companies of the AEP System and their electric service areas are: (1) Ohio Power Company (OPC), serving an extensive area of Ohio; (2) Indiana & Michigan Electric Company (I&M), serving the northern and east central parts of Indiana and the southwestern corner of Michigan; (3) Kentucky Power Company (KPC), serving eastern Kentucky; and (4) Appalachian Power Company (Appalachian), serving western Virginia and the southern part of West Virginia.

In addition, the AEP System includes three other operating companies: Kings-port Power Company, Michigan Power Company and Wheeling Electric Company. These companies purchase their electrical power and energy from the four principal operating companies at wholesale and resell the power and energy to customers in small areas of Tennessee, Michigan and West Virginia. The System also contains one generating company which owns and operates generating facilities, Kanawha Valley Power Company. This company, a wholly owned subsidiary of Appalachian Power, sells all of its output to its parent. Both I&M and OPC once had generating subsidiaries, Indiana & Michigan Power Company and Ohio Electric Company, respectively, but the subsidiaries have merged into their parent utilities.

The petitioners in No. 79-3628, AEP Service Corporation, OPC and KPC, are subsidiaries of AEP. The petitioners in No. 79-3698 are the Michigan Public Service Commission (Michigan Commission), which regulates the retail electric rates of I&M in Michigan; the Public Service Commission of Indiana (Indiana Commission), which regulates the retail electric rates of I&M in Indiana; and the Indiana and Michigan Municipal Distributors Association (IMM-DA), whose member municipalities purchase electric power and energy from I&M for resale to retail customers. The petitioner in No. 79-3685 is the Public Utilities Commission of Ohio (Ohio Commission), which regulates the retail electric rates of the Ohio Power Company.

I

On July 6, 1951, the principal system operating companies, Appalachian, I&M, OPC and AEP Service Corporation (then American Gas & Electric Service Corp.) signed an Interconnection Agreement, which was designed to give the system members the benefits and advantages of large scale, coordinated operation and planning of electric supply facilities owned by, or available to, the members. KPC signed the agreement in 1962. One of the features of this agreement is a primary capacity equalization charge. This charge fixes the rate at which AEP System utilities purchase electric generating capacity from each other to supplement the capacity of their own systems to meet customer demands and reserve requirements. Members with generating capacity deficits make payments to members with surplus generating capacity in amounts set by the rate. Under the 1951 agreement, the capacity cost portion of the equalization charge was a fixed charge of $1 per kilowatt of capacity per month, which was based upon the assumption of an installed cost of generating capacity of $100 per kilowatt and an annual fixed carrying charge rate of 12 per cent.

II

On April 29, 1975, the AEP Service Corporation filed with the Commission a proposed modification to the Interconnection Agreement, pursuant to § 205 of the Federal Power Act, 16 U.S.C. § 824d. Acting as agent for OPC, I&M, KPC and Appalachian, AEP Service Corporation proposed Modification No. 3 which would, among other things, increase the primary capacity equalization charge from the fixed rate of $1 per kilowatt per month to a rate designed to reflect the changed circumstances of the System and the economy. The new rate would be determined by multiplying the weighted average investment cost per kilowatt of the installed generating capacity of the surplus members by an annual carrying charge rate of 17.5 per cent (1.46 per cent per month). The average capacity costs were to be updated annually to include new capacity additions. For further details of the provisions of the 1951 Interconnection Agreement and the changes brought about by Modification No. 3, reference is made to the decision of the Commission in the Appendix.

By an order issued on May 30, 1975, the Commission accepted the proposed Modification No. 3 for filing, suspended its operation for one day, permitted it to go into effect subject to refund, and ordered a public hearing concerning its lawfulness under §§ 205 and 206 of the Federal Power Act, 16 U.S.C. §§ 824d&e. A hearing was held before an administrative law judge, who allowed a number of parties, including certain public regulatory agencies, to intervene. Of the intervening agencies, only the Ohio Commission presented evidence for the record before the administrative law judge and participated actively in the hearing.

The parties who participated in the proceedings took one of two basic positions. They either supported Modification No. 3 as written or they supported an alternative version of the modification which contained a capacity equalization charge based upon incremental capacity investment cost rather than the weighted average of capacity investment costs.

In his lengthy initial decision, issued on February 23, 1978, more than 33 months after the proposed Modification No. 3 was filed, the administrative law judge rejected the positions of all the parties. He found, among other things, that Modification No. 3 “would increase the primary capacity equalization charge to a deficit member of the system in a discriminatory manner [and, therefore, would not] be just and reasonable.”

Specifically, the ALJ found that the capacity equalization charge as proposed in Modification No. 3 would discriminate against I&M. Under Modification No. 3, I&M, as a deficit member, would have to increase its payments under the capacity equalization charge significantly. As a result, the payments to OPC, a surplus member, also would increase significantly. The ALJ found such an increase in payments to be discriminatory, because, while I&M was deficient in generating facility capacity, it had contributed more than its share in generating facility investment. This situation had arisen because I&M, at the direction of AEP Service Corporation, had invested in a high capital cost, low operating cost, nuclear facility, the Cook plant. OPC, on the other hand, had invested in a lower capital cost, higher operating cost, coal-fired facility, the Gavin plant. The Gavin plant also was built at the direction of AEP Service Corporation, which has responsibility for planning the installation of all generating units of the system.

To substantiate his conclusion that Modification No. 3 discriminated against I&M for the above reasons, the ALJ quoted from the brief submitted to him by AEP:

AEP pointed out in its brief that, “Had I&M taken the funds which it invested, through its subsidiary, in the Cook plant and- invested them instead in a coal-fired' plant like Gavin, the AEP system would be radically different from what it is today. For instance, assuming the Cook plant will eventually cost $450 per kilowatt of installed capacity, I&M’s total investment will be in the order of $990 million. Had I&M’s subsidiary invested these $990 million in coal-fired plants at a cost of $230 per kilowatt of installed capacity, it would have added roughly 4,300 megawatts to its MPC [Member Primary Capacity], or almost double the 2,200 megawatts which it will obtain from Cook. On the other hand, if OPC’s subsidiary had invested the $588 million it spent on Gavin in a nuclear plant like Cook, it could have only added on the order of 1,200 to 1,300 megawatts to the MPC

Thus, the administrative law judge reasoned that the capacity equalization charge should be predicated upon the relative investment of the member utilities in generating capacity and not upon the relative capacities of the members in kilowatts of power. Rather than developing a capacity equalization charge based upon the investment of each member utility in generating capacity as a percentage of the total generating capacity investment of the system, the ALJ merely directed AEP to retain the primary capacity equalization charge of $1 per kilowatt per month as provided in the 1951 Interconnection Agreement.

At this point, the Michigan Commission and IMMDA intervened, and the Indiana Commission abandoned its support for Modification No. 3. These three parties urged the Commission to remand the proceeding to the administrative law judge for rehearing so that the parties could adduce evidence to support the ALJ’s theory or advance any other proposals they might deem appropriate. The other parties to the proceedings excepted to the decision of the ALJ or dropped out of the proceedings altogether.

Upon the basis of the record before it, the Commission rejected the opinion of the administrative law judge. On May 21, 1979, the Commission circulated to the parties a draft opinion recommended by its advisory staff. The draft opinion provided for the approval of Modification No. 3 with certain minor changes. The Commission, sitting en banc, heard oral arguments on the draft opinion on June 20. On July 27, 1979, the Commission issued Opinion No. 50 (see Appendix hereto), which approved the draft opinion, adopting Modification No. 3 basically as proposed by the AEP Service Corporation. It further ordered (1) that the monthly carrying charge factor used in calculating payments under the Agreement be reduced from 1.46 per cent per month to 1.37 per cent per month; and (2) that AEP System utilities with surplus capacity refund to AEP System utility purchasers the capacity equalization charges collected in excess of the new 1.37 per cent rate. By its later order of September 24,1979, the Commission denied all applications for rehearing, but ruled that refunds could be accomplished by bookkeeping entries among the AEP System utilities in lieu of cash reimbursements because “intercompany charges and payments are handled as accounting transactions on a consolidated basis.”

After their applications for rehearing had been denied, the petitioners sought review in this court under § 313(b) of the Federal Power Act, 16 U.S.C. § 8257 (b). The three petitions for review were consolidated for hearing. After considering the matter on the oral arguments of counsel, the briefs of the parties and the voluminous record, we affirm the decision of the Commission, but without prejudice to reconsideration of Modification No. 3 by the Commission in new proceedings.

Ill

This court stated the standard for judicial review of Commission decisions under the Natural Gas Act in Ashland Oil Co. v. Federal Power Commission, 421 F.2d 17, 22-23 (6th Cir. 1970):

On a petition to review orders of the Commission under the Natural Gas Act, the scope of review of the Court of Appeals is limited. As to factual matters the findings of the Commission are conclusive if supported by substantial evidence. 15 U.S.C. § 717r(b); Cincinnati Gas & Electric Co. v. F. P. C., 389 F.2d 272 (6th Cir.), cert. denied, 393 U.S. 826, 89 S.Ct. 89, 21 L.Ed.2d 97. As to other matters within the jurisdiction of the Commission under the Act, a reviewing court accords deference to the Commission as a specialized agency created by Congress to deal with complex problems. California Gas Producers Ass’n v. F. P. C., 383 F.2d 645 (9th Cir.).

As to such matters this Court does not substitute its judgment for that of the Commission, even though we do not “accept the agency determination in blind faith.” Skelly Oil Co. v. F. P. C., 375 F.2d 6, 31 (10th Cir.), modified on other grounds, sub nom., Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312, rehearing denied, 392 U.S. 917, 88 S.Ct. 2050, 20 L.Ed.2d 1379. As to matters other than the issue of whether there is substantial evidence to support the Commission’s findings, this Court reviews to determine whether a rational basis exists for a conclusion, Consolidated Edison Co. of New York v. F. P. C., 271 F.2d 942, 953 (3rd Cir.), rev’d on other grounds, 365 U.S. 1, 81 S.Ct. 435, 5 L.Ed.2d 377; see, also Michigan Wisconsin Pipe Line Co. v. F. P. C., 263 F.2d 553 (6th Cir.); or whether there has been an abuse of discretion, Michigan Gas & Electric Co. v. F. P. C., 110 U.S.App.D.C. 183, 290 F.2d 374, cert. denied, 368 U.S. 897, 82 S.Ct. 177, 7 L.Ed.2d 95; Battle Creek Gas Co. v. F. P. C., 108 U.S.App.D.C. 209, 281 F.2d 42; or to determine whether the Commission’s order is arbitrary or capricious or not in accordance with the purpose of the Act. Kentucky Natural Gas Corp. v. F. P. C., 159 F.2d 215 (6th Cir.); J. M. Huber Corp. v. F. P. C., 294 F.2d 568 (3rd Cir.). (Footnotes omitted.)

These principles, enunciated in a natural gas case, apply to this court’s review of an electric rate proceeding under the Federal Power Act. Federal Power Commission v. Sierra Pacific Co., 350 U.S. 348, 349-51, 76 S.Ct. 368, 369-70, 100 L.Ed.2d 388 (1956). In prescribing just and reasonable rates, the Commission may “devise methods of regulation capable of equitably reconciling diverse and conflicting interests.” Permian Basin Area Rate Cases, 390 U.S. 747, 767, 88 S.Ct. 1344, 1360, 20 L.Ed.2d 312 (1968).

The Commission is “free, within the ambit of [its] statutory authority, to make the pragmatic adjustments which may be called for by the particular circumstances.” FPC v. National Gas Pipeline Co., 315 U.S. 575, 586, 62 S.Ct. 736, 743, 86 L.Ed. 1037 (1942).

The appropriateness of a rate approved by the Commission raises issues of fact. The role of the court in reviewing the Commission’s rate decisions under 16 U.S.C. § 8251(b) is “essentially narrow and circumscribed.” Permian Basin Area Rate Cases, 390 U.S. 747, 766, 88 S.Ct. 1344, 1359, 20 L.Ed.2d 312 (1968).

The three consolidated petitions raise the following issues: (1) Whether the Commission’s decision is supported by substantial evidence on the record considered as a whole (Nos. 79-3685 and 79-3698); (2) Whether the Commission’s determination of the monthly carrying charge factor used in calculating the primary capacity equalization charge was unlawful and unreasonable and unsupported by the record (No. 79-3685); (3) Whether the Commission’s approval of a capacity equalization charge based upon embedded cost, rather than the incremental cost, of a surplus member’s capacity is unjust, unreasonable, discriminatory and unlawful, in violation of §§ 205(a) & (b) and 206 of the Federal Power Act, 16 U.S.C. §§ 824d(a) & d(b), 824e (No. 79-3685); (4) Whether the Commission’s approval of a capacity equalization charge predicated upon the relative generating capacities of the members, and not upon the relative investments in generating capacity, was unjust, unreasonable, discriminatory and unlawful, in violation of §§ 205(a) & (b) and 206 of the Federal Power Act, 16 U.S.C. §§ 824d(a) & (b), 824e (No. 79-3698); and (5) Whether the Commission abused its discretion in directing that the capacity equalization charges collected in excess of the amounts payable under the reduced rate be refunded (Nos. 79-3628 and 79-3685).

Upon consideration of the record, the court concludes that the decision of the Commission is supported by substantial evidence; that the Commission acted within the powers delegated to it by the Federal Power Act; that the Commission properly refused to follow the reasoning of the administrative law judge; that the other issues raised by the petitions do not require reversal or remand; and that the decision of the Commission should be affirmed, subject to the right of the petitioners to initiate new proceedings before the Commission for reexamination of Modification No. 3.

IV

The petitioners in Nos. 79-3685 and 79-3698 urge this court to remand the case to the Commission so that they may have an opportunity to introduce additional evidence. The Commission asserts that, despite a full opportunity to do so, the Ohio, Indiana and Michigan Commissions and IMMDA failed to make a record to support their claims. In view of the great length of these proceedings and the extensive delays that have prevented a speedy resolution of the issues, we conclude that a remand is not justified on the present stale record. Again we make it clear, however, that nothing in this opinion is intended to preclude a new proceeding brought by complaint under 16 U.S.C. § 825e with respect to any of the alleged infirmities in Modification No. 3 raised by petitioners.

The Commission included the following passage in its opinion in the present proceeding:

[W]e believe it appropriate, in response to the positions taken by several of the state Commission intervenors, to emphasize again the sui generis nature of our determination herein, a determination which reflects and in large measure is predicated on the existing circumstances of capacity availability of AEP’s integrated system .... [T]his decision involves a balancing of equities and an accommodation of diverse interests necessitated by present supply circumstances, rather than the application of the theoretically superi- or'method. We would anticipate that when the present large intercompany disparity between supply and demand is reduced, an opportunity will be available for re-examination of the operation of the Interconnection Agreement.

At another point in its opinion, the Commission said:

While affirming the use of average embedded costs in this case, we emphasize that our determination is predicated on the make-up of the AEP system as it now exists. The decision on this issue should not be considered as precedential in any future consideration by the Commission of this Agreement or of other interconnection arrangements. (Emphasis supplied.)

V

Although we affirm the conclusion reached by the Commission, we do not intend to express complete satisfaction with its opinion. We view Opinion 50 as an effort to reach a practical solution to the present proceeding. We find the following passage from the concurring opinion of Commissioner Holden to be appropriate:

I withhold further objection to, and concur in the issuance of, the order of the Commission in this docket. The present order is a pragmatic solution and the case is of vintage quality, having been filed more than four years past and having been decided by the Administrative Law Judge seventeen months ago. Hence, no further delay is warranted.

However, I do believe it is a matter that we shall have to revisit.

* * * * * *

Whether the investment basis, rather than the kilowatt capacity basis, for allocation is the right alternative, I do not now judge. Nor do I even have a provisional view that it would be superior. I do believe the dollars versus kilowatts choice deserves systematic comparison and a determination.

I do not preclude the possibility that even with a fuller record, the Commission should ultimately come to the same decision as is embodied in the present order. It is not necessary to attempt to resolve that question here. The record available to the Commission does not allow that determination.

All that is necessary is to observe that the Commission should probably review the interconnection agreement when there is a reasonable basis to believe that a superior practical alternative might, in fact, be developed. Whether this should involve a rate case under Section 205, a proceeding under 206, some form of broader examination under a Federal-State joint board format, collaboration with the NARUC, or some form of proceeding in which the relevant authorities of the Secretary of Energy to adopt an intervenor status might be utilized is a matter to be examined at some more appropriate time.

One example of the deficiencies in the opinion of the Commission is its failure to deal expressly with the issue of undue discrimination. The administrative law judge found:

The changes in the Interconnection Agreement proposed by the parties to this proceeding would increase the primary capacity equalization charge to a deficit member of the system in a discriminatory manner and have therefore not been proven to be just and reasonable.

The Michigan and Indiana Commissions and IMMDA contend that Modification No. 3 is discriminatory and asserted that position before the Commission sitting en banc and before this court. The Commission held that the changes in the Interconnection Agreement proposed by Modification No. 3 “are just and reasonable and should be approved,” but did not mention expressly the issue of undue discrimination, even though it is required by statute to address that question. See 16 U.S.C. § 824e(a); FPC v. Conway Corp., 426 U.S. 271, 279, 96 S.Ct. 1999, 2004, 48 L.Ed.2d 626 (1976).

The Commission asserts that the Indiana Commission was an intervenor virtually from the start of the proceedings but did not introduce any evidence into the record, nor did it actively participate in the cross-examination of witnesses sponsored by AEP Service Corporation or the FERC staff, but it in fact supported Modification No. 3 before the AU issued his decision; and that the Michigan Commission and IMMDA did not intervene until after the ALJ’s decision and never advanced a counterproposal which could have been accepted on the basis of substantial evidence. The Commission also relies on language in its opinion which it interprets to demonstrate that it considered the discrimination issue and decided it adversely to the petitioners in Nos. 79-3698 and in 79-3685.

There is no doubt that the issue of undue discrimination was before the Commission. It was raised in the opinion of the ALJ and by the Indiana and Michigan Commissions and the IMMDA. We express no view as to whether the Commission or the parties themselves had the burden of producing evidence on the issue of undue discrimination. See Public Service Commission of New York v. FERC, 642 F.2d 1335, 1345 (D.C.Cir.1980), cert. denied, - U.S. -, 102 S.Ct. 360, 70 L.Ed.2d 189 (1981); Public Service Company of New Mexico v. FERC, 628 F.2d 1267, 1270-71 (10th Cir. 1980), cert. den. sub nom. Gallup v. FERC, 451 U.S. 907, 101 S.Ct. 1974, 68 L.Ed.2d 295 (1981); Public Service Commission of Indiana v. FERC, 575 F.2d 1204, 1216-17 (7th Cir. 1978). We hold only that the record as a whole does not justify a remand on the discrimination issue. It is obvious, however, that the Commission’s treatment of this issue could have been more explicit.

The decision of the Commission is affirmed, but without prejudice to subsequent consideration by the Commission of the 1951 Interconnection Agreement and Modification No. 3 in later proceedings. No costs are taxed. Each party will bear its own costs in this court.

APPENDIX

OPINION NO. 50

OPINION AND ORDER APPROVING AMENDMENT OF INTERCONNECTION AGREEMENT WITH MODIFICATIONS

(Issued July 27, 1979)

Before Commissioners: Charles B. Curtis, Chairman; Georgiana Sheldon, Matthew Holden, Jr., and George R. Hall.

This proceeding is before us on exceptions to an initial decision issued after hearings by a presiding administrative law judge. An oral argument, with the Commission sitting en banc, was held on June 20, 1979. The notice scheduling the argument included a draft opinion which had been prepared for the Commission’s consideration by its Office of Opinions and Review. This procedure, which is innovative at least insofar as this Commission is concerned, was utilized primarily because of the complexity of the proceeding and the fact that the conclusions proposed differed substantially from those suggested by the law judge. The draft decision was made available to the parties in advance of the oral argument in order to better enable them to address their remarks to the matters considered to be an [sic] issue in the proceeding as well as to comment on the suggested resolution. It appeared at the argument that the release of the draft decision was well received and, we believe, its availability contributed to the presentation of more sharply focused argument. We will continue to utilize this procedure whenever, in our opinion, considerations of time and the circumstances of the particular proceeding warrant.

In general we find that we have not been persuaded by the discussion at the oral argument that the resolution recommended in the draft decision is substantially in error. To the contrary, we are more firmly convinced that the proposed determination is in the overall public interest at this time. Thus, while the present decision differs in few respects from the draft opinion, we believe it appropriate, in response to the positions taken by several of the state Commission intervenors, to emphasize again the sui generis nature of our determination herein, a determination which reflects and in large measure is predicated on the existing circumstances of capacity availability on AEP’s integrated system. As recognized in several of the comments at the oral argument and as brought out subsequently, this decision involves a balancing of equities and an accommodation of diverse interests necessitated by present supply circumstances, rather than the application of the theoretically superior method. We would anticipate that when the present large intercompany disparity between supply and demand is reduced, an opportunity will be available for re-examination of the operation of the Interconnection Agreement.

* * *

This proceeding involves a proposal by the American Electric Power Service Corporation (AEP), filed April 29, 1975, to amend an Interconnection Agreement dated July 6, 1951,¹ executed by the principal operating subsidiaries of the AEP system establishing the charges for sales of power and energy among the interconnected companies. The proposed amendment, which is referred to as Modification No. 3 (Mod. 3), was suspended for one day and then was permitted to go into effect subject to refund pending a determination of its lawfulness under Sections 205 and 206 of the Federal Power Act.²

The four principal operating companies of the AEP System and their electric service areas are (a) Appalachian Power (Appalachian), serving in western Virginia and in the southern part of West Virginia, (b) Indiana & Michigan Electric (I&M), serving in the northern and east central parts of Indiana and the southwestern corner of Michigan, (c) Kentucky Power (KPC), serving in eastern Kentucky, and (d) Ohio Power (OPC) serving an extensive area in Ohio. The AEP System also includes three generating companies, each organized as a wholly-owned subsidiary of one of the principal operating companies, which own and operate generating facilities. The generating subsidiaries sell at wholesale and deliver all of the power and energy they produce to their respective parent companies, pursuant to contracts filed with the Commission as rate schedules. The generating companies are (1) Ohio Electric Company (Ohio Electric), a wholly-owned subsidiary of OPC, which owns and operates the Gavin Plant, located in southern Ohio, consisting of two 1,300,000 kW coal-fired generating units which were placed in service in 1974 and 1975; (2) Indiana & Michigan Power Company, (Indiana & Michigan Power), a wholly-owned subsidiary of I&M, which owns and operates the Cook Plant, located on Lake Michigan near Bridgman, Michigan, consisting of two 1,100,000 kW nuclear generating units, the first of which was placed in service in 1975, and the second of which was placed in service in the summer of 1978; and (3) Kanawha Valley Power Company, a wholly-owned subsidiary of Appalachian, which since the 1930’s has owned and operated under license two hydroelectric generating facilities, located on the Kanawha River in West Virginia, having a capability of 51,000 kW.

As indicated above, an initial decision was issued on February 23, 1978. That decision contains a review of the procedural history of the case, the provisions of both the 1951 Agreement and the changes occasioned by Mod. 3, and the positions of the parties.

Despite our desire to avoid repetition of material already set out in the initial decision, some brief description of Mod. 3 and of staff’s proposed alternative is useful as an aid in comprehending the various issues in dispute. The principal effect of Mod. 3 is to increase the primary capacity equalization charge used in determining the amount of compensation for primary capacity surpluses and deficits among the parties to the Agreement. The previously used charge consisted of a uniform capacity rate of $1.00 per kilowatt per month and an annual fixed charge rate of 12% plus a weighted average fixed operating cost. Mod. 3 provides for the retention of the previously used weighted average fixed operating cost but would replace the $1.00 per kW per month capacity rate with a rate based on the more recent embedded capacity costs of the individual system members.³ It also includes a fixed monthly carrying charge factor of 1.46%, equivalent on an annual basis to a rate of 17.5%.

Another major change involves the elimination of a ceiling imposed on economy energy charges, whereby such charges were limited to not more than 125% of the out-of-pocket costs incurred by the member supplying such energy. This change maintains the basic formula set out of [sic] the 1951 Agreement, which is essentially a sharing between buyer and seller of the savings resulting from the transaction.

Three minor changes to the 1951 Agreement also are embodied in Mod. 3. These changes involved the elimination of all “secondary energy” and “secondary capacity” classifications, the elimination of a lag in the recovery of costs, and a change in the definition of “member primary capacity” to permit a member, with the concurrence of the other members, to purchase capacity from a “foreign” (i.e. any nonaffiliated) company and to include such capacity as primary capacity of the member.

The Commission staff presented testimony urging that the primary capacity equalization charge contained in Mod. 3 was too low. It recommended that the charge be based upon the costs of the most recent generating units installed by surplus members, rather than on the average or embedded costs of generating capacity of surplus members as provided in Mod. 3. Staff also opposed the “split-savings” method of pricing economy energy charges contained both in the 1951 Agreement and in Mod. 3. Finally, staff presented testimony opposing the return component of the proposed 17.5% annual carrying charge rate reflected in Mod. 3 and recommended the use of the actual embedded capital costs of each surplus member in calculating the capacity equalization charges.

In light of the detailed description contained in the February 1978 decision, we shall forego a further recounting of these elements except as necessary to support the findings and conclusions developed herein. The administrative law judge determined that the changes which would be made by Mod. 3 in the primary capacity equalization charge and in the economy energy charge had not been proven to be just and reasonable. He likewise found that the even more substantial change (in terms of monetary effect) to the primary capacity equalization charge proposed by two parties, Ormet Corporation and Kaiser Aluminum and Chemical Corporation,⁴ and the staff were unsupported by the record and also should be rejected. The law judge recommended adoption of the subsidiary changes proposed in Mod. 3 involving elimination of the “secondary energy” and “secondary capacity” classifications and of a lag in the recovery of costs. In all other respects he found that the rates and charges embodied in the 1951 Agreement as it existed prior to Mod. 3 were reasonable and recommended the refund of all amounts collected in excess of those levels. The decision makes clear that in reaching his conclusion the law judge was influenced by his determination that the changes proposed to the Interconnection Agreement were deficient in failing to accord adequate recognition to the investment in capacity made by each of the AEP operating subsidiaries.

The exceptions by the parties to the initial decision continue to reflect, in general, the positions previously taken by them in the proceeding. Thus, AEP persists in seeking approval of its proposed Mod. 3 without change; the Indiana and Michigan Municipal Distributors Association, the Michigan Public Service Commission and the Indiana Public Service Commission support the law judge’s decision; the West Virginia Public Service Commission supports the law judge’s recommendation to deny the increase in the primary capacity equalization charge but excepts to his finding on the definition of member primary capacity; the Public Service Commission of Kentucky objects to the law judge’s recommendation that the Interconnection Agreement be recast to recognize each company’s investment in generating capacity; and the Public Utilities Commission of Ohio and the staff believe that Mod. 3, while moving in the proper direction, does not go far enough and affirm their support of the further changes recommended by staff. The Ohio Commission has indicated that the charge established by Mod. 3 “insufficient though it may be, is the very least acceptable alternative.” Staff, which had advocated the charging of its recommended higher rate as of the effective date of the Mod. 3 filing and that AEP “be required to submit a refund plan to provide for flowing through amounts ordered to be paid above the pool charges [currently in effect] in the form of credits to the total costs of service of retail and wholesale customers who ultimately paid excessive amounts because of the unreasonable low pool rate,”⁵ appears to have moderated its position on the matter of refunds. In its final filing staff raises the possibility of making the higher pool charges which would result from its recommendations, effective only prospectively from the date of the Commission’s decision, without disturbing the charges paid and received by the respective AEP companies under Mod. 3 during the period of the refund obligation.⁶

DISCUSSION

Witnesses were presented by AEP to support its claim that changed conditions required modification of the 1951 Agreement. The testimony indicated that the capacity equalization charge incorporated in the original Agreement was predicated on a cost of approximately $100 per kW of installed generating capacity and that this amount continued reasonably to reflect the average cost of installed capacity of the various member companies until approximately 1970. Beginning at about that time, AEP claims, two circumstances combined to warrant a change in the. charges for capacity between deficit and surplus members. First, the cost of capacity additions installed by the AEP companies in the 1970’s increased to levels substantially in excess of that reflected in the 1951 rate and, second, a number of generating additions planned by several of the AEP companies were can-celled or deferred for various reasons, including financing limitations, increasing constraints on the availability of sites for large generating facilities, the necessity for compliance with environmental control regulations and delays in obtaining requisite federal and state regulatory authorizations to construct new generating facilities. Because of the cancellations and deferrals of major generating capacity additions, AEP’s witness explained, largely for reasons not wholly within the system’s control, it became apparent that the desired rotation of surplus generating capacity among the different companies would not occur and that OPC which had added a large amount of capacity at the Gavin Plant of Ohio Electric, its subsidiary, would remain a surplus company for a considerable period of time. Conversely, I&M would remain deficit in capacity until well into the 1980’s despite the very substantial investment in new capacity represented by the Cook Plant.

The evidence confirms each of these assertions by AEP. The record shows that the average system cost of capacity increased markedly in the 1970’s with the addition of the 2600 mW coal-fired Gavin Plant at a cost of $588 million and the 2200 mW nuclear fueled Cook Plant costing $990 million. Plans for the construction of a new coal-fired plant and a pumped storage hydroelectric plant by Appalachian were abandoned, as was the addition of two 1,300 mW coal-fired units scheduled for installation by I&M. In short, the evidence establishes the validity of AEP’s claim that a change became necessary in the rates and charges levied under the Interconnection Agreement in that the then existing charges did not continue to reflect adequately a proper sharing of the benefits and burdens of the generating capacity available on the AEP system.

As indicated earlier, staff and the Ohio Commission do not agree with the proposition inherent in Mod. 3 which bases the capacity equalization charge on the average investment cost of the surplus members’ generating units other than hydro. Although both acknowledged that Mod. 3 would help to overcome the inadequacy of the capacity rate included in the 1951 Agreement they assert that the new charge is insufficient in that it fails to compensate those pool members with surplus capacity for the actual costs of building such capacity. Staff contends that the equalization charge should be based on the investment cost of the generating units actually used to supply the deficient capacity — which it interprets as “usually a member’s latest units” — rather than on the average investment cost of all units of the surplus companies. Staff also argued that the associated fixed charges should be calculated on the costs of the units supplying the deficiencies. The Ohio Commission, which has as its main concern in this proceeding the revenues received by OPC as a surplus member of the system, supports staff’s claim that the charge should be based on the surplus member’s latest unit (or units) of capacity, and not on a system average or embedded cost.

Prior to our determination of this fundamental issue in dispute, it is necessary to address another matter raised in the initial decision and the subject of some exceptions, namely the status under the Agreement of the Gavin and Cook Plants. The law judge concluded that the capacity represented by these plants was not includable as primary capacity of OPC and I&M, respectively, but instead should be treated as capacity made available by transactions with “foreign companies” under Article 7 of the Interconnection Agreement. While the question whether capacity owned by an affiliate of a member company comes within the Agreement’s definition of “member primary capacity” ⁷ is not entirely clear, we believe the weight of the evidence supports AEP’s and the West Virginia Commission’s claim that capacity available to members from generating subsidiaries is properly classified as primary capacity of such members.

None of the parties to the proceeding challenged such inclusion by AEP nor was any question raised to suggest that a redefinition of member primary capacity was necessary to include specifically the capacity of wholly-owned subsidiaries. The practice of the AEP companies is consistent with this conclusion as can be seen from the fact that Appalachian has had available all of the 51,000 kW of hydroelectric generating capacity owned by its wholly-owned subsidiary, Kanawaha [sic] Valley Power Company, and this capacity has been included as primary capacity of Appalachian from the inception of the Agreement in 1951. We are also influenced by the express definition of foreign company in the 1951 Agreement (Section 0.4) as encompassing “non-affiliated electric utility companies ...” (including the Tennessee Valley Authority, which interconnects with Appalachian) in establishing the mode of treatment to be accorded the costs and benefits flowing from transactions with such companies. On the other hand, it does appear that where the framers of the original Agreement distinguished between “member primary capacity” and “member secondary capacity” (Sections 5.9 and 5.10), they were careful in the latter category to include not only the relatively less efficient capacity installed at generating stations of a particular member, but also such capacity at “. . . generating stations not owned by said Member but where the operation and production costs thereof are the responsibility of said Member.” Thus, it appears that adequate specificity was included where the need was foreseen.

We perceive no statutory or other public interest consideration which mandates the use of criteria based on legal title or direct ownership of generating capacity (as opposed to ownership through the mechanism of wholly owned subsidiaries) where the reasons for the existing mode of ownership are known (at least for the Gavin and Cook Plants) and where the operation and sales are fully consistent with the purposes intended to be served by the Interconnection Agreement. The treatment of the Kanawha capacity as primary capacity over a course of more than twenty years without challenge upholds AEP’s contention that Section 5.7 prescribes substantive, operating criteria for eligibility as primary capacity, irrespective of whether the capacity is available to a member directly through ownership or indirectly through a wholly-owned subsidiary supplying all of its capacity or energy to its parent by contract.

We note that Mod. 3 would amend the definition of “member primary capacity” to make clear its inclusion of both (a) capacity installed at generating stations owned by the member and (b) capacity available to the member through interconnection arrangements with affiliated companies or foreign companies. We believe this modification is beneficial in eliminating the uncertainty inherent in the original definition. Insofar as foreign company purchases are concerned, this represents an improvement over the original treatment provided in Article 7. In addition to providing more clarity, the redefinition of member primary capacity set out in Mod. 3 would allow a deficit member to purchase capacity from a non-affiliated company and thereby decrease or eliminate its capacity deficit for pool purposes. To the extent that such purchases may aid in minimizing the long-term deficit capacity status of I&M and Appalachian, and foster enhanced competition, increased reliability and regional coordination, we believe the amendment serves a salutary purpose.

Section 5.7 of Mod. 3 vests the Operating Committee with the responsibility of determining whether additional capacity made available to a member as a result of an interconnection arrangement should be treated under Section 5.7(ii) [capacity available through interconnection with affiliated or foreign companies] or Article 7 [transactions with foreign companies]. The law judge found that this redefinition would provide the operating Committee with “unwarranted discretion.” Considering all of the changes to the existing Agreement which are to be affected by Mod. 3, it is our conclusion at this time that legitimate reasons may well exist for lodging such discretion in the Operating Committee. However, to assure that the authority is exercised consistent with purposes intended, AEP is directed to file appropriate guidelines for including such purchases as primary capacity of the member instead of as foreign purchases under the Agreement. The law judge’s determination on these matters is reversed.

Staff questioned the fact that while capacity purchases from foreign companies are to be included in member primary capacity, capacity sales are not excluded. AEP’s response was not fully definitive and a vagueness was left in the record on this matter. The draft opinion had proposed that sales of firm capacity be deducted from the aggregate capacity of a member in calculating that member’s primary capacity. At the oral argument, however, AEP’s counsel pointed out that this procedure would not take into account the reserves which must be maintained by the selling member to support the sale. He also noted that § 5.7 of the Interconnection Agreement already provides that such sales are added to the seller’s load in determining the Member Load Ratio. Staff counsel appeared to concede the validity of this argument.

The problem arises from the fact that the amendment to Section 5.7 is not specific in its use of the term “capacity.” It appears that staff’s witness was concerned with the failure of the Agreement to treat sales of unit capacity and other non-firm capacity sales by one member to another, or by a member to a non-member utility. We agree that these forms of sales, if effected, should be deducted from the capacity available to the selling member as well as (as Mod. 3 provides) being added to the capacity of the purchasing member. The treatment of firm sales is proper under the Agreement and no further modification is necessary with regard thereto.

A question was raised in the initial decision regarding the status under the Agreement of the Cook Nuclear Generating Plant as part of I&M’s primary capacity. Observing that the definition limits primary capacity to “steam generating plants and hydro,” the law judge seemingly held that a revision of the definition would be a prerequisite to the inclusion of Cook capacity. Again, in dealing with production expenses, he concluded that the costs of nuclear generation would be excluded by the original Agreement.

We do not accept the law judge’s interpretation that the Cook Nuclear Plant is not a “steam generating plant.” The Cook units are pressured water reactor systems which utilize superheated water to produce steam which turns turbine-generators. While the source of the heat used to produce the steam differs from that in the more common fossil-fueled generating plant, we find no basis for distinction within the definition contained in the Interconnection Agreement to support a conclusion that the Cook Plant is not comprehended within the generic category of steam generating stations.

One other major change, beside that involving the capacity equalization charge, would be occasioned by Mod. 3.⁸ Under Section 6.6 of the 1951 Agreement, economy energy was priced on the “split-savings” method, i.e., the out-of-pocket incremental cost of the supplying member plus one-half of the difference between the supplier’s incremental cost and the out-of-pocket decremental cost of the receiving member. However, the 1951 Agreement contained a limitation that the supplier could not receive more than 125% of his out-of-pocket costs. Mod. 3 would eliminate the ceiling so that economy energy would be priced wholly on a split-savings basis.

Staff opposed the basic split-savings method for the pricing of economy energy. Staff argued that the economy energy rate should be set at the supplier’s cost, determined after the transactions have taken place, and should be based prospectively on the costs of the units used in supplying the economy energy. Staff’s witness testified that the filed economy energy charge is unreasonable in that (1) it may have a greater tendency than the superceded charge to prolong unit outages and may influence decisions to retire less efficient generating units, and (2) it is based on “simplified cost computation methods not commonly used by centrally dispatched power pools.”⁹

Elimination of the 125% ceiling has the effect of permitting an equal sharing of the cost savings from an economy energy transaction between the supplier and the recipient. Conversely, the operation of the ceiling in the 1951 Agreement could have the effect, depending on the particular circumstances, of allocating a disproportionate share of realized cost savings to the recipient of economy energy.

Staff’s witness did not defend the ceiling, nor did he support its deletion. Rather, he recommended an economy energy rate based solely on the supplier’s cost. Although we appreciate the concerns prompting staff’s recommendation, there is no evidence in the record that any such inappropriate actions or imprudence occurred during the 25 years of operation under the 1951 Agreement. Moreover, we have continued to monitor the operations under Mod. 3 since it was placed in effect provisionally in 1975 and find no basis for concern in the areas raised by staff. In sum, we find that the split-savings provision in Mod. 3 is one of a variety of reasonable methods for allocating the savings derived from economy energy transactions and has been accepted in prior Commission decision [sic].¹⁰ The amendment to the prior provision to eliminate the 125% ceiling is accepted and the provision in Mod. 3 is approved.

We return now to the basic issue in this proceeding, that of the method to be used in calculating the primary capacity equalization charge. We have referred earlier to the differences between staff’s proposed charging method and that contained in Mod. 3. Full details are provided in the initial decision. It is our conclusion, after study of the record and consideration of the arguments presented by the parties, that the charges levied under the 1951 Agreement do not reflect the increased costs of recent capacity additions and are therefore outdated, unfair and unreasonable, and that a change is required to reflect the present day benefits and burdens relating to the generating capacity installed by the AEP member companies. It is our further conclusion that staff’s proposal of basing the charge on the investment cost of the units supplying the needed capacity to the deficit members is the superior method in theory in that it would assure that the member with surplus capacity was more completely compensated for the actual ownership costs incurred in making surplus capacity available to capacity deficient members. Moreover, the economic decisions of the various member companies related to power sources (new capacity additions, purchasing from pool members and purchases from foreign companies) would be more soundly based and the design of the rates charged by the companies, retail as well as wholesale, would be based on realistic costs — as would the economic decisions of the companies’ retail customers relating to their energy supplies. We also are aware of other desirable (although less certain) advantages of staff’s proposal, including the timely installation of new generating units, the encouragement of competition among pool members and neighboring utilities, the promotion of regional coordination and, since the charges would be based on marginal cost pricing principles, the fostering of energy conservation at the retail level.

Nevertheless, despite our acknowledgement that staff’s capacity equalization method has advantages over AEP’s Mod. 3 proposal, it is our determination that its recommendation should not be adopted in this case. Instead, the Mod. 3 method for calculating the primary capacity equalization charge will be approved. However, as discussed hereafter, we do not accept the justification provided for the Monthly Carrying Charge Factor and therefore amend the factor provided in Mod. 3.

Our decision to allow the capacity equalization charge based on the average investment costs of the surplus members rests entirely on the circumstances present in this case, namely (1) the relative distribution of capacity surplus and deficiencies among the AEP member companies; (2) the fact that the existing status has remained constant since 1968 and is expected to persist well into the 1980’s; (3) recognition of the disproportionate investment in capacity made by I&M vis-a-vis the other members and the heavy burden of that investment on I&M’s ratepayers — a burden which would be increased under staff’s proposal — and (4) the fact that, in the final analysis, the issue involves a matter of degree since even staff and the Ohio Commission admit that the Mod. 3 charge is an improvement over that contained in the original Agreement.

We accept for present purposes AEP’s assertion that the systems of the four member companies participating in the Interconnection Agreement are planned and operated as a single, integrated utility system with the result that new generating and bulk transmission facilities are planned on an overall AEP .system basis with due consideration to the requirements of the individual members. We likewise are aware, as pointed out earlier, that a number of planned additions of new generating capacity have been cancelled or deferred. These additions would have eliminated, or at least significantly improved, the deficit capacity status of I&M and Appalachian and, we believe, would have provided for a more reasonable rotation of excess capacity among the member companies than exists at this time. While AEP is endeavoring to construct new capacity to meet its anticipated loads in the various service territories, it is obvious that no major change in the existing pattern of supply will occur for a number of years.

Although I&M made a heavy investment in its Cook Nuclear Plant — $990 million by the time of the second unit’s activation in 1978 — it realized only 2200 mW of capacity, or an investment cost of $450 per kW. Construction on the Gavin fossil fired plant, on the other hand, resulted in the addition of 2600 mW of capacity at a total cost of $588 million, or only $226 per kW. While hindsight may indicate that I&M would have been better served from a capacity cost standpoint by the construction of a non-nuclear generating plant, there is no suggestion that the decision to undertake this plant was in any way imprudent. We note also that for 1976 and 1977 the overall cost per kWh of the energy produced by the Cook Plant was relatively low. Although I&M, as a deficit member, does not receive payments for capacity under the Agreement, it and its customers have the direct benefits associated with the low fuel costs of the Cook Plant energy. It must also be recognized that the Cook Plant is situated on Lake Michigan at the northwestern point of the entire AEP companies’ service area, near I&M’s principal load centers and removed from access to the coal reserves and coal transportation facilities along the Ohio River. In essence, we find no reason to conclude, under these circumstances, that the primary capacity equalization charge is defective in failing to reflect the investment in capacity made by the deficient members.

While affirming the use of average embedded costs in this case, we emphasize that our determination is predicated on the make-up of the AEP system as it now exists. The decision on this issue should not be considered as precedential in any future consideration by the Commission of this Agreement or of other interconnection arrangements.

In addition to basing the capacity equalization charge on the average installed cost per kW of the surplus member, Mod. 3 specifies a “Monthly Carrying Charge Factor”, used in calculating the payments for capacity, of 0.0146, or 17.5% on an annual basis. Capital costs are the largest single component of the carrying charge and have been included on the basis of an overall cost of money (rate of return) of 11.50%.¹¹ Staff’s witness testified that if the investment portion of the equalization charge is based on the costs of the latest units, the appropriate capital costs should be then associated with the latest units. Staff’s cost of capital evidence, however, was entirely on an embedded cost basis. While it made no attempt to calculate a rate of return on the capital cost of the latest units, it recommended that AEP be ordered to develop such a rate of return for each member.

We have decided, in our prior discussion, not to adopt staff’s recommended “newest unit” theory for determining the capacity equalization charge. This being so, there is no merit to the suggestion for basing the rate of return on the associated capital costs of the latest units.

In the event the Commission decided against the use of the costs of capital associated with latest units, staff proposed separate rates of return for the four member companies based in their embedded costs and respective capitalization as of December 31, 1974.¹² The overall returns ranged from 8.71% for Appalachian (12.75% on equity) to 9.47% for I&M (13.00% on equity).¹³ AEP recommended the use of a single, systemwide capital structure and an overall return of 11.18% to 11.51%. The company requested a rate of 9.0% to 9.5% on debt, 11.0% to 11.5% on preferred stock, and 15% on equity.

Without unnecessarily prolonging this discussion, and considering the purposes served by the Carrying Charge Factor, we accept as reasonable the unified capital structure recommended by AEP in the calculation of the return allowance, i.e., 57% long-term debt, 10% preferred stock, and 33% common equity.¹⁴ However, we will not accept AEP’s incremental cost rates for debt and preferred stock. In line with the embedded cost approach being followed in this case, we believe that the costs of senior capital should also be reflected on an embedded cost basis and should additionally take into account the consolidated operations of the four Member Companies. The testimony of AEP witness Barber states that the weighted embedded costs of long-term debt and preferred stock issued by the four Member Companies were approximately 7.0% and 7.9%, respectively, at June 30, 1975.¹⁵ It is evident, however, that the 7.0% cost of debt does not reflect the debt of the generating subsidiaries as we believe it should.¹⁶

On the other hand, staff’s Exhibit S-5 does present the capital structures and cost rates of the four member Companies on a consolidated basis as of December 31, 1974.¹⁷ Employing the data in this exhibit, we can derive an embedded cost of debt of 7.75% and embedded cost of preferred stock of 7.41%. The preferred stock rate, however, does not include a 14% preferred stock issue in 1975 that is taken into account in AEP’s calculations.¹⁸ Consequently, we will use the 7.9% preferred stock rate as the latest record evidence available along with our derived 7.75% cost of debt.

The testimony of the parties on the appropriate allowance for equity capital is of limited usefulness. AEP’s defense of its request for a 15% return on common equity is exceedingly general and, consequently, not very persuasive, while staff’s recommendation was based on separate rates of return for the four Member Companies, whereas we have opted for a single rate of return in this case. Nevertheless, based on statistical data presented in staff’s Exhibits S-5 and S-6 and AEP exhibit P-14, and in consideration of equity returns recently allowed by this Commission, we find that a return on common equity of 12.75% is just and reasonable. The application of these cost rates to the above mentioned capital structure results in an overall rate of return of 9.42%. The inclusion of this cost of capital component, together with an adjusted component for Federal income taxes, results in annual and monthly carrying charge factors of 16.49% and 1.37%, respectively.

The Commission further finds:

(1) Ohio Power Company, Indiana & Michigan Electric Company, Appalachian Power Company and Kentucky Power Company are each a public utility as defined in the Federal Power Act and the sales by them of electric energy pursuant to the Interconnection Agreement dated July 6, 1951, are sales of electric energy at wholesale in interstate commerce subject to the jurisdiction of the Commission.

(2) The amendment to the Interconnection Agreement proposed by Modification No. 3 to increase the primary capacity equalization charge is just and reasonable under the existing circumstances and should be approved, except that the monthly carrying charge factor should not exceed 1.37%.

(3) The changes in the Interconnection Agreement proposed by Modification No. 3 for the purpose of eliminating the system secondary capacity and secondary energy classifications, and for the elimination of lag in the recovery of costs, are just and reasonable and should be approved.

(4) Ohio Power Company, through its agent, American Electric Power Service Company, should be required to file appropriate guidelines applicable to the exercise by the Operating Committee of its discretion in determining when a purchase by a member of capacity from a non-affilated [sic] company shall be included as “member primary capacity” under Section 5.7(ii) of the Interconnection Agreement.

(5) Section 5.7 of the Interconnection Agreement should be amended to exclude sales of unit capacity and other sales of non-firm capacity from member primary capacity.

The Commission orders:

(A) Modification No. 3 to the Interconnection Agreement dated July 6,1951, filed as Ohio Power Company’s F.E.R.C. Rate Schedule No. 23, is approved subject to the following conditions:

(1) Section 6.212 of the Agreement shall be changed to reflect a monthly ' carrying charge factor of 0.0137.

(2) Guidelines shall be submitted for the Commission’s approval applicable to the Operating Committee’s exercise of its discretion in determining when a purchase by a member of capacity from a non-affiliated company will be included as member primary capacity under Section 5.7(ii) of the Agreement.

(3) Section 5.7 of the Interconnection Agreement should be amended to assure exclusion of sales of unit capacity and other sales of non-firm capacity from member primary capacity.

(B) The filings required by Ordering Paragraph (A) shall be submitted within 30 days of the date of issuance of this Opinion.

(C) Ohio Power Company shall file an annual statement of the member weighted average investment cost as provided in Section 6.211 of the Agreement, including the basis for the amounts shown therein.

(D) Within 60 days from the date of issuance of this Opinion, Ohio Power Company shall provide a statement reflecting appropriate credits for all sales of energy under Modification No. 3 due to the required modification in the monthly carrying charge factor.

(E) Exceptions not granted are denied.

(F) The Initial Decision is affirmed to the extent consistent with this Opinion and Order.

By the Commission. Commissioner Holden, concurring, filed a separate statement appended hereto.

American Electric Power

Service Corporation

Docket No. E-9408%bl

1 . The proceedings were commenced before the Federal Power Commission. As of October 1, 1977, the Federal Energy Regulatory Commission, an independent regulatory agency within the Department of Energy, succeeded to certain functions and regulatory responsibilities of the Federal Power Commission. See Department of Energy Organization Act, 91 Stat. 565 (1977), 42 U.S.C. §§ 7101 et seq. (Supp. I 1977), and Executive Order No. 12009, 42 Fed.Reg. 46267 (Sept. 13, 1977).

1 . Filed as Ohio Power Company’s F.E.R.C. Rate Schedule No. 23.

2 . This proceeding was commenced before the Federal Power Commission (FPC). By the joint regulation of October 1, 1977 (10 CFR 1000.1), it was transferred to the FERC. The term “Commission”, when used in the context of action taken prior to October 1, 1977, refers to the FPC; when used otherwise, the reference is to the FERC.

3 . AEP’s witness McNulty testified that the embedded capacity cost calculated for each member would be updated each year based on data available as of the end of the next preceding year (Tr. p. 148).

4 . Though active throughout the hearings, both Ormet and Kaiser apparently have discontinued their representation efforts and did not file exceptions to the initial decision.

5 . Brief on Exceptions, p. 37.

6 . On February 21, 1979, the Virginia State Corporation Commission filed a request for late intervention in order to participate in the remaining stages of this proceeding. The request for limited intervention is granted.

7 . Section 5.7 defines “member primary capacity” as “The more efficient steam and hydro capacity installed at the generating stations of the members normally expected to operate and carry load.” (emphasis added)

8 . We have referred earlier to the elimination of the “secondary energy” and “secondary capacity” classifications, and of a lag in the recovery of costs. These changes were approved in the initial decision and no exceptions were filed on these issues. These changes are confirmed.

9 . Tr. p. 314.

10 . E.g., Gainesville Utilities Dept. v. Florida Power Corp., 40 FPC 1227, 1235, 1245 (1968); Public Service Company of Indiana, et al., 47 FPC 1396, 1405, 1410 (1972). See 1970 National Power Survey, Part I, pages 1-17-8 and 9.

11 . Exh. P-8.

12 . Exh. S-5, p. 1.

13 . Staff recommended 9.29% overall for OPQ (13% on equity) and 8.78% for KPC (11.5% on equity).

14 . Tr„ p. 269.

15 . Tr., p. 270.

16 . Exh. P-11, p. 2 of 2.

17 . Tr., p. 439.

18 . Exh. P-12.